U.S. DOT/RSPA - Draft Final Regulatory Evaluation

Page 1U.S. Department of Transportation Research and Special Programs Administration Draft Final Regulatory Evaluation Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) Docket RSPA-00-7666#

Page 2INTRODUCTION The U.S. Department of Transportation Research and Special Programs Office of Pipeline Sal ety (OPS) is proposing to change pipeline safety regulations to require operators of certain pipelir es to validate the integrity of their pipelines in high consequence areas. The rule would apply to operators of natural and other gas transmission lines. The objective of the change is to reduce the risk of pipeline incidents in these areas. The OPS defines a high consequence area as: All class 3 & 4 locations. These are areas where there are at least 46 buildings intend€ d 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. (Are i s within class 3 & 4 locations but outside of the “potential impact zone”, as defined in tl le proposed rule, are considered medium consequence areas). Locations where any hospital, school or other facility having persons who are confineci or of limited mobility are in a circular impact zone having radius equal to a “threshold radius” defined based on the diameter and operating pressure of the pipeline. Locations where 20 or more persons congregate at least 50 days in any 12-month peric d are in this circular impact zone (pipeline within 100 yards of such locations is conside .ed class 3 under the current definition in 49 CFR 192.5). Locations where the radius of the circular impact zone exceeds 660 feet and where an! circle of 1000 ft. radius (or larger for some large-diameter, high-pressure pipelines) centered on the pipeline includes 20 or more buildings intended for human occupancy The 20 building limit within a 1000 ft. radius circle has been established to ensure the same building density as in Class 3 Locations (see above). To validate the integrity of their pipelines in high consequence areas under the regulatory chai ige, pipeline operators must implement an integrity management program for such pipelines incluc ling periodic inspection and testing and integration of information related to pipeline integrity. Th 2 purpose of this report is to assess the benefits and costs of the proposed 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 environmental consequences of leaks from hazardous liquid pipelines are different than those from natural gas pipelines. The elements of an integrity management program proposed to be required by this rule are similar, however, to the elements previously required of hazardous lic pid pipeline operators. This report considers the costs and benefits of these proposed requirement s in a manner similar to the analysis of costs and benefits prepared for the earlier rulemakings. TARGET PROBLEM 1#

Page 3Natural and other gas pipeline breaks can result in explosions and fires that can impact on hur ian 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 protectioi 1. The OPS is promulgating this regulation to afford the necessary additional protection to these “high consequence areas”. Numerous investigations by the OPS and the National Transportation Safety Board (NTSB) h we highlighted the importance of protecting the public from pipeline failures. The NTSB has ma le 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 the OPS to undertake additional safety measures in areas that are densc.1~ populated. These statutory requirements included having the OPS prescribe standards for identifying 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 protectior to high consequence areas. These alternatives were: 1. No action. 2. Prescriptive requirements for inspection and repair of pipelines in high consequence areas. 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 I isk. 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. They perform inspectic n and testing on their pipelines to assess their integrity, and make repairs as they conclude they ire needed. These actions would be expected to continue under the “no action” alternative. 2#

Page 4Pipeline leaks and ruptures occur, despite the existence of these operator programs. Major pipeline accidents have occurred in recent years, of which two were particularly notable, at Ec ison 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 th, it eventually caused the rupture or the damage occurred in the years following the inspection. It addition, the operator failed to integrate information about the pipeline, including the presencc 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 ow spot which could not be inspected by pigging. The operator failed to consider the possibility ,f such accumulation of moisture and resulting corrosion and thus did not intercede to prevent tl e pipeline failure. An integrity management program involving integration of all safety-signifil :ant information about the pipeline could have prevented both of these accidents. The OPS conch des that validation of operator’s integrity management programs through audit and review by outs ide 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. In the absence of requirements, pipeline operators might choose to curtail or eliminate some or all inspection and testing. The OPS concludes that assuring continuation of pipeline integrity management programs, assuring that their scope encompasses all areas requiring special protection, and verifying thei r adequacy 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 prob ’ em. In addition, continued reliance on voluntary industry efforts would not be responsive to the Congressional mandate that the OPS promulgate requirements to assure protection of the area ; that 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 ind 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 addre ss 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 inefficient use of industry ai id government resources to establish requirements in this fashion. Compliance inspection woulci still require that the requirements applicable to specific pipelines be identified for comparison with ongoing practices. 3#

Page 5Prescriptive requirements also would tend to stifle technological innovation. They do not allc w for different approaches based on advances in the technology. The technology associated wit1 i in- line inspection of pipelines (Le., pigging) is advancing at a rapid pace. Establishing prescriptive requirements could slow this advancement, or could preclude use of new techniques that may be developed. In the extreme, prescriptive requirements could stop technological innovation in t lis area completely. Most importantly, however, establishing prescriptive requirements would not assure the integration of information which experience has shown is vital to preventing pipeline acciden s. As noted above, two major accidents have occurred in recent years despite the fact that information about the causative factors should have, or could have, been known. It appears t k at 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 that ultimately resulted in failure of the pipe. An integrity managemei it 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 1 s complete and properly implemented. This outside review cannot be assured without a requirement for such a program. For these reasons, the option of establishing prescriptive requirements was not evaluated furtf er 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 1 isk. Pipeline operators are uniquely qualified to develop integrity management programs and prov de for the necessary integration of information. They have the best knowledge of their pipelines md 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 difficu It to require through prescriptive regulation. Requiring that operators develop such programs is th ; best way to assure that they exist. Such a requirement also provides the regulatory basis for tl e OPS 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 pipe line accidents. They cannot, however, eliminate that risk. Leaks and ruptures could still occur, frc im 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 availablt: to mitigate the effects of accidents that may occur. Here again, circumstances differ between pipelines and between regions and local jurisdiction s. The differences make it difficult to establish prescriptive requirements that will provide the bt st protection for each high consequence area. Requiring that operators explicitly consider the nc ed for mitigative features and provisions and that they implement those found necessary is the m 1st 4#

Page 6effective means of providing such protection. Such a requirement also provides the regulator basis for audit and review by OPS and state regulators. For these reasons, this option was selected for hrther development. 4. Requiring pipeline operators to develop integrity management programs providing for expedited inspection and retesting. The OPS considered the need for requiring integrity management programs that would requirt inspection and testing of pipelines to recur over short intervals, a few years. The ability to rec uire 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 reguli ltion 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 fro1 n environmental damage that can be caused by a leak or rupture of a hazardous liquid pipeline necessitated such frequent inspection. Adding requirements for similarly frequent inspection i f 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 practica 1 matter, operators meet this requirement by reducing operating pressure or using heavier-walle 1 pipe in class 3 and 4 areas. Hazardous liquid pipelines do not afford similar protection in higl L 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 thc case for hazardous liquid pipelines, which move product in batches and have significant stora ;e capacity. Assessment of natural gas pipelines can therefore result in interruptions of gas supp y. 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 likelihoo 1 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. 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. 5#

Page 7The Pipeline Safety Improvement Act of 2002 requires assessments on no greater than 7-year intervals. The OPS has established requirements in this proposed rule that would provide for a more focused assessment on this shorter interval. The OPS evaluated the effect on costs to operators of requiring full assessments at increased intervals, as described later in this analysi, ;. Costs would increase significantly without addition of commensurate benefits. For these reasons, the OPS 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. 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. The OPS has interacted with gas pipeline operators in recent years as part of development of: n integrity management standard by the American Society of Mechanical Engineers (ASME). 'I 'he standard includes many of the elements of the proposed rule, and has been adopted as a conselisus standard. As a result of these interactions, the OPS understands that many gas pipeline operators currently have integrity management programs including many aspects that would be required by this proposed 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 beilig conducted by these operators is the initial inspection of pipelines. The rate at which subseque nt 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 pipe1 ne would not be reinspected at all. Integrity management plans are a key element of this rule. To better understand and promote more comprehensive and integrated approaches to safety and environmental protection, the 0 i'S created the Risk Management Demonstration Program, and the System Integrity Inspection Pi lot Program. These programs encourage and evaluate operator-developed safety and environmen tal management processes that incorporate operator- and pipeline-specific information and data tl 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 fai lure could have significant consequences. 6#

Page 8Through the Risk Management Demonstration Program and the System Integrity Inspection Pilot Program, the OPS 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 1 o their pipeline systems. In the Risk Management Program, participants perform systematic an( 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 risk assessmer ts is the integration of information from many diverse sources to fully understand the integrity t h e ats at specific locations on the pipeline. The impact on nearby population is explicitly considerer in these risk assessments. Through formal, risk-based decision making processes, these compan ies use the risk assessment results to identify projects and activities that address potential system integrity threats, thereby preventing leaks and accidents. These investigative risk managemen t 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 OPS inspections. Instead of using a “checklist” approach, the OPS is focusing th : inspection process on an operator’s integrity management processes and activities. Through working with the operator, the OPS is able to understand and influence the methods and approaches used to assess pipeline integrity, and the approaches to integrating integrity assess nent data with other pipeline specific information to identify the most significant integrity threats t I the system. Specifically, the OPS has observed how operators examine internal inspection data i t 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 the OPS is acquiring a broader understanding and a greater confidence that effectii’e 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 i s risks, and use this information to make sound integrity management decisions. The OPS experience in the Risk Management Demonstration Program and the System Integri y Inspection Program indicates that integrity management programs such as that required by thi ; rule have been developed. They are far from universal, however. REVIEW BY TECHNICAL PIPELINE SAFETY STANDARDS COMMITTEE The OPS presented a preliminary draft of this regulatory analysis to the Technical Pipeline Sa fety Standards Committee (TPSSC) at a public meeting on July 18, 2002. 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 TF SSC provided extensive comments on the preliminary draft regulatory analysis, which have been considered in developing this draft version. 7#

Page 9Of greatest significance were comments indicating that the natural gas pipeline industry intent Is to implement this proposed rule, if finalized, by a preponderance of in-line inspection. As descr bed later in this analysis, the OPS presumed that some pipelines that can be modified easily to accommodate in-line inspection devices would be so modified, but presumed that no pipe tha would require significant modification costs would be pigged. Industry members of the TPSS C reported, instead, that much “hard-to-pig” pipe would be modified and that pigging would be Jsed as the assessment method of choice. This represents an industry conclusion that pigging is thc ; most cost-effective means of conducting assessments, even if significant up-front capital cost:, are required to modify existing pipelines. At the same time, the industry members of TPSSC repc n-ted that reliance on hydrostatic testing would be significantly less than the OPS had estimated in 1 he preliminary draft analysis. High costs, environmental issues associated with disposing of wat :r used for hydrostatic tests, and operational difficulties that could result from watedmoisture le t in pipelines after assessments all contribute to the relative undesirability of this assessment metl- od. This draft analysis has been revised to reflect these relative industry priorities. With respect tl) the intent to modify hard-to-pig piping, this is presented herein as an alternative. For reasons described below, the OPS still has some doubt that significant amounts of hard-to-pig pipe wi 11 be modified. The TPSSC also commented that the OPS had underestimated the costs associated with the proposed rule. In particular, estimates for programmatic costs (i.e., those associated with developing integrity management programs and implementing related information analysis) v, ere noted to be low, industry’s estimate of the cost of hydrostatic testing - particularly in urbanizc d areas where natural gas distribution companies operate - was much higher than that used by tl Le OPS, and the amount of additional mileage that must be pigged (since pig launchers and receivers are not generally located on the boundaries of high consequence areas) was noted to be significantly underestimated. The OPS has limited data regarding current costs for developing integrity management programs. The cost ranges used in the preliminary draft analysis were based on a survey conducted sevei a1 years ago. Interactions with hazardous liquid pipeline operators, who are developing integritj management programs in response to similar rules promulgated earlier, indicate that these ran zes likely do underestimate actual costs. The OPS had increased the costs assumed for programrr atic activities, above those used in the analysis of the hazardous liquid rules, but the TPSSC commented that the increases were not enough. The OPS has further increased the cost estim ites for these activities in this draft analysis, as described below. The per-mile cost estimate for hydrostatic testing used in the preliminary draft regulatory analysis, and in this analysis, is based on a 1990 study. It is possible that costs for such testing have increased over the last twelve years by more than the rate of inflation. Little hydrostatic testir g has been performed in recent years, particularly in urbanized areas. The OPS has no more rec mt data on what the costs of such testing would be, and has not changed the per-mile cost estimai es used in this analysis. As described above, however, industry’s belief that the costs and diffia lties associated with hydrostatic testing will be significant has much reduced the relative important e 8#

Page 10expected to be placed on this assessment method. The OPS has revised downward its assumr tion of how much mileage will be subjected to hydrostatic testing, making any disagreement in thc per- mile cost relatively less important. The OPS was persuaded by TPSSC discussion that the amount of mileage that must be piggeci in order to assess mileage that can affect high consequence areas was underestimated in the preliminary draft analysis. That analysis estimated an additional 25 percent of pipeline mileal ;e would be pigged (i.e., the total pigged would be 1.25 times the high consequence area mileagt ). This is the same additional percentage assumed in the analyses supporting similar rules for hazardous liquid pipelines and was used for both pigging and hydrostatic testing. Industry representatives on the TPSSC used a similar assumption for additional mileage for hydrostatic testing. They reported, however, that launchers and receivers for in-line inspection devices ar 2 spaced much farther apart than valves that will be used for hydrostatic testing. They estimate( I that the additional mileage that will be pigged will be up to several hundred percent of the mileage that can affect high consequence areas. The OPS has reflected these comments in this analysi; by assuming that 200 percent additional mileage will require pigging in order to assess the milea ;e that can affect high consequence areas and which will be assessed using in-line inspection. Finally, it is significant to note that the TPSSC supported proceeding with this proposed rule despite the significant comments made concerning the regulatory analysis. The committee, a~ d public representatives of the pipeline industry that made presentations at the public meeting, expressed the belief that the benefit associated with improved public confidence in pipeline s; fety justifies the costs associated with the proposed rule. The TPSSC unanimously adopted a mot on finding that the draft cost-benefit analysis supports the concepts for a proposed standard for integrity management programs for gas transmission pipelines'. PIPELINE SAFETY IMPROVEMENT ACT OF 2002 The Congress passed the Pipeline Safety Improvement Act of 2002 subsequent to the public meeting with the TPSSC. The Act requires that natural gas pipeline operators implement inte gity management plans, and that the Department of Transportation promulgate regulations govem ng these plans. The Act specifies, however, that assessments of pipelines covered by operator integrity management plans must occur at no greater than seven (7) year intervals. This periodicity is greater than considered in the analysis discussed with the TPSSC. The OPS has revised the proposed rule, and this analysis, to be responsive to the assessment periodicity requirements in the Act. For reasons described above, under Alternatives Conside red, and as described in the appendix to this analysis, the OPS concluded that requiring assessmen1.s using traditional methods at intervals of seven years or less was not necessary. The OPS has, instead, included in the proposed rule a more-focused application of direct assessment. The 'TPSSC meeting transcript, July 18,2002, RSPA-1998-4470-68 9#

Page 11proposed rule would require that assessments using pressure testing, in-line inspections, direct assessment, or an equivalent technology be used at intervals of five, ten, or fifteen years (depending on factors to be described later in this analysis), as considered in the analysis discussed with the TPSSC. The proposed rule further requires that operators assure that an assessment, using one of these methods or the more-focused method described in the rule, are used at least every seven years. This analysis has been revised, from the version discussed wit n the TPSSC, to reflect this additional method and requirements. 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. Then the potential benefits of the rule are discussed. In the next section the potential costs of the rule are examined. Finally, a discussio 1 of the costs versus the benefits is presented. It should be noted that, unless otherwise specified, i 11 dollar values in 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. Includir Lg 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 are expected to be 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 292 thousand miles of regulated natural gas transmission pipelinzs in the U.S.3 This rule would not apply to all of this mileage. The proposed rule does not apply tl) pipelines operated at a hoop stress of less than 20 percent of specified minimum yield strengtk (SMYS). The OPS has no data on how much transmission pipeline mileage is operated at the ;e low stresses, but presumes that it is small. The rule also applies to transmission pipelines for hydrogen, synthetic gas and other products subject to 49 CFR Part 192 that are not included ir the natural gas transmission pipeline totals. Here, again, the OPS does not have data on the total transmission mileage for these other gases. This analysis uses the available natural gas 'Dollars are converted from nominal values to real 2001 values using the Producer Price Index (PPI), Intermedi, ite Materials, Supplies, and Components. The source of the PPI index numbers is the U.S. Bureau of Statistics We11 page. 'Jurisdictional natural gas transmission pipeline mileage (onshore) for 2000. This mileage was obtained from annua I reports filed by pipeline operators with the Office of Pipeline Safewata available on the OPS web page. 10#

Page 12transmission pipeline total mileage, which is considered to be very close to the total pipeline mileage potentially affected by the proposed regulation. Impacted Mileage in High Consequence Areas The proposed regulatory change does not apply to all of this pipeline. Instead, it applies to thi I t transmission pipeline that can affect high consequence areas, as described earlier. A principa element of this definition is pipeline that is in class 3 and 4 areas as defined in 49 CFR 192.5. Pipeline operators are presently required to maintain data on the population near their pipelint in order to determine pipeline that is in class 3 or class 4 areas. Historically, this data has not be :n required to be submitted to the OPS. Reporting of mileage by class was required for the first ime as part of the 2001 annual reports from gas transmission pipeline operators. At the time this analysis was prepared, a total of 2 8 3 18 miles had been reported in those reports as class 3 or 4. Analysis of the 2001 reports was not complete, however. Only approximately 256,000 on-shc Ire miles of natural gas transmission pipeline had been reported. For purposes of this analysis, th 2 OPS presumes that the total amount of on-shore natural gas transmission mileage did not deci ease significantly between 2000 and 2001 and that the percentage of class 3 and 4 mileage in the a! -yet unreported 36,000 miles is the same as that in the 256,000 miles reported. This results in a conclusion that an additional 4,010 miles of pipeline exists in class 3 and 4 areas, for a total o 32,528 miles. There are several factors in the definition of high consequence areas which could lead to additional mileage being included. These include: e e . the requirement to consider the location of buildings that could house populations of limited mobility, the requirement to consider areas near pipelines where people congregate, and the requirement to expand the radius of consideration to 1000 feet (or possibly more) for pipelines larger than 30 inches in diameter and operating at pressures greater than 101 10 psig or where calculations of potential impact radius indicate a likelihood that areas beyond 660 feet from the pipeline would be affected by an accident. The OPS cannot know with certainty how much additional mileage that can affect high consequence areas will be added by these criteria. The definition of piping that can affect hig I consequence areas for natural gas transmission pipelines is only now being finalized. Provisic ms of this proposed rule add additional factors that further refine the definition. Pipeline operato 's are not required presently to collect data related to these additional factors, and the OPS has n independent source of such information. For purposes of this analysis, the OPS assumes that these additional factors would increase the total transmission pipeline mileage affected by the rule by 30 percent, or 9,758 miles. The OPS seeks comments on the reasonableness of this assumption. 11#

Page 13The OPS would like operators to apply the definition of high consequence areas and submit comments indicating how much additional mileage (Le., beyond that in classes 3 and 4) is identified. The OPS also would like to receive information regarding how this mileage is distributed. The OPS expects that mileage in urbanized areas, whether classes 3 or 4 or inclul led as a result of one of the other criterion, will be reasonably concentrated, with a significant por ;ion of any piggable segment (Le., launcher to receiver) so identified. At the same time, the OPS expects that piping in rural areas that meets the definition as piping that can affect high consequence areas (e.g., due to the proximity of areas where people congregate) will be much more distributed. In rural locations, such areas may constitute only a few miles of a piggable segment. The distribution of these areas may affect decisions regarding the method of assess1 lent operators will use, as discussed below. The total gas transmission pipeline mileage in high consequence areas is thus 42,286 miles, tl e sum of the amount estimated to be in class 3 and 4 areas and the amount assumed to be added as a result of other factors in the definition of high consequence areas. The state of Texas has already promulgated a regulation requiring assessment of intrastate nat xal gas transmission pipelines within the state. The provisions of the Texas rule require assessmc nt at intervals that are more frequent than those in this proposed rule. As a result, this proposed ru e will not impose additional assessment requirements on Texas intrastate natural gas transmissi In lines, and the total mileage of such pipeline must be subtracted from the national total to determine the mileage affected by this proposed rule. The Texas Railroad Commission repon s that there are 37,5 10 miles of intrastate natural gas transmission pipeline within Texas4 The 'IPS assumes that the percentage of this mileage in high consequence areas is the same as the percentage of total U.S. transmission pipeline mileage that is affected. The Texas mileage th; t must be subtracted therefore amounts to 5,432 miles. The total gas transmission pipeline mileage in high consequence areas that is considered in th s analysis to be affected by this proposed rule is thus 36,854 miles. BENEFITS The benefits resulting from the proposed regulatory change are discussed in this section. Tho ;e benefits are expected to result from detection of problems that could cause pipeline failures bc :fore the failure occurs, thereby averting accidents. The inspection and assessment that would be required by the proposed rule is designed to detect problems related to internal corrosion, extc mal corrosion, stress corrosion cracking and external damage to the pipeline, all of which can resu It in pipeline ruptures. Natural gas pipeline accidents usually involve explosions and fire and can result in death, serious injury, and property damage. Preventing accidents will result in reduced numbers of deaths and serious injuries and in reduced property damage. These reductions, thc :n, are principal benefits of the proposed rule. The proposed rule will also provide improved 4Data from Texas Railroad Commission web site, http:/lwww.rrc.state.tx.us/divisions/gslsmiles-html. 12#

Page 14assurance of pipeline safety, will provide a basis for increased public acceptance of the risks f -om natural gas transmission pipelines, and will provide other, less tangible, benefits. Each of the, ;e categories of benefits is discussed below. Pipeline operators also have strong incentives to ensure the integrity of their pipelines. In add ition to the positive safety and societal benefits, the lost product and unscheduled downtime for rep airs following a major incident can significantly impact the company’s financial performance and its ability to satisfy customer commitments. Operators cannot afford to have these critical transportation assets out of service for lengthy periods of time in today’s competitive busines: environment. In addition, the damage to the company’s public image and reputation, as well I is the legal implications of serious incidents, can pose an even broader and longer term negative impact on the company’s business operations. For these and other reasons, many pipeline operators have implemented and are continuing to improve more systematic safety and environmental management processes, many of which already embody the principles in this proposed rule. Benefits from reduced death and serious inju$ Accident reports submitted to the OPS during the period 1986 to 2001 (this period was chose] I because this data is publicly available on the OPS website) identify that there were 1,285 incir lents on natural gas transmission pipelines, resulting in 58 fatalities and 217 serious injuries. The consequences of future pipeline accidents could differ, and are likely to be more severe, as discussed below. Nevertheless, it is reasonable to use this 16-year record as an estimate of consequences that would be likely to occur without changes in the manner in which pipeline safety is assured. (Although the accident data base is 16 years and costs are calculated in this analysis for 20 years, this is not a problem as the accident data is used only as an average bent fit estimate per year and is not used to compare total benefits to total costs.) The proposed rule is expected to reduce these consequences, through identification and remediation of the kinds of anomalies that can cause pipeline accidents before those accidents occur. Accidents that will 3e prevented by the proposed rule should include a high percentage of those that result in death a nd serious injury, since the rule is focused on pipelines in areas which have the largest concentrai ions of people in the vicinity of the pipeline. The proposed rule will not eliminate all pipeline accidents. It is not possible to estimate precisely how effective it will be in reducing such accidents. The theoretical maximum benefit that could be achieved would be elimination of accidents causing death and serious injury. Based on this historical record, the maximum vali Le that could be realized from reducing deaths and serious injuries is thus $282.5 million over 1t 5With respect to deaths and serious injuries, the following assumptions are made: A life is valued at $3 million A serious injury is valued at $500 thousand These valuations are standard assumptions currently used in Office of Pipeline Safety and DOT benefidcost analyses. 13#

Page 15years or $17.65 million per year.6 Benefits from reduced property damage The same accident data base indicates that $284,829,617 in property damage occurred as a res ult of those 1,285 pipeline incidents. A recent study indicates that this total may be low due to UI (der- reporting of accident The study compared accident costs reported to the OPS with other information, including pre: s reports and costs reported in operators' post-accident financial filings: The study considered 1.9 accidents, of which only four were natural gas pipeline accidents. (Two of these accidents ha( l not been reported to OPS). The study found that actual costs for accidents involving hazardous li pid pipelines were three times the amount reported to the OPS. For the limited set of gas pipeline accidents considered, costs were under-reported by a factor of 1.62. The OPS believes that a larger study of gas pipeline accidents might show more under-reporting of costs, similar to tht situation revealed for hazardous liquid pipelines. For purposes of this analysis, the OPS assui 2es that costs may have been under-reported for natural gas pipeline accidents by up to a factor of 2. Thus, the true value of property damage experienced in natural gas transmission pipeline incic ents over the last 16 years is in the range of $285 to approximately $570 million. This range is used in this analysis as representative of the property damages caused by historic a1 natural gas pipeline accidents. As before, the historical record provides a reasonable estimate of the consequences of potential future accidents. Again, the proposed rule is expected to reduct the number of accidents, and thus the amount of property damage that occurs. The extent of such reduction cannot be estimated. The maximum benefit that could be achieved if the historical damage is at the upper end of this range and property damage consequences were eliminated tmy implementation of the proposed rule is $570 million over 16 years, or $35.6 million per year. Consequences of Pipeline Accidents are Likely to Increase Urban areas are rapidly expanding in the United States. Housing starts have increased 57% o.ier the last ten-year period. Increasingly, this brings additional population into the proximity o f t le natural gas transmission pipelines that serve our urban areas. Rural areas that pipelines may k ave 6The accident data used here is national data. Since intrastate transmission pipeline in Texas has been excluded from this analysis, the contribution of any accidents on that pipeline should also be excluded. This has not been done. The OPS did not examine the specific accident reports that lie behind the tabulated accident informa ion on its web site for the period 1986 to 2002, and does not know whether any intrastate Texas pipeline is represent :d in that data. None of the major accidents in this period occurred on that pipeline. The OPS expects that the effe :t of excluding accidents on intrastate Texas pipelines from the computation of benefits in this analysis would be sma' 1, likely well within the errors associated with the simplifying assumptions used to make the analysis possible. 7"Report on the Accuracy of Cost Data from Incident Reports", General Physics Corporation, Decembe ~ 200 1, un ublished. 'The OPS has not attempted to exclude any property damage occurring during this period on Texas intrastate natural gas transmission pipelines for the same reasons described above for deaths and serious injuries. 14#

Page 16passed through ten years ago are more likely today to be populated, and that likelihood will further increase over time. Natural gas pipeline accidents that occur in rural areas have limited consequences, particularly in causing deaths and serious injuries. Accidents in urban areas cati be much more severe. The March 23, 1994, accident in Edison Township, New Jersey is a case in point. This area vras already urbanized at the time of the accident, but the accident demonstrates the potential for n iajor consequences. Rupture of a 36-inch diameter natural gas transmission line resulted in an explosion and fire that destroyed six apartment buildings. Property damage exceeded $25 mi’ lion. Approximately 1,500 residents were evacuated from the apartments. Immediate evacuation prevented any deaths, although one resident living approximately one mile from the scene of 1 he accident suffered a fatal heart attack.’ Had circumstances been only a little different, signific: nt loss of life could have occurred. Increased development makes it likely that the actual consequences of natural gas pipeline accidents over the next 16 years, assuming no changes in the regulatory environment, would t e more severe than suggested by the historical record. The OPS has not estimated by how mucl L those consequences might increase, because such an estimate would be highly speculative. Nevertheless, the trend indicates that use of the historical record to estimate the likely consequences of future accidents is almost certainly conservative. The total benefit represented by the historical record is approximately $53.25 million per year, the sum of the benefits for deaths and serious injuries and for property damage as described abovl :. The OPS believes that the proposed rule will have significant effect in reducing the occurrent,: of the kinds of accidents that resulted in these consequences. Given the magnitude of the potent a1 benefit represented by the historical record and the likelihood that consequences of future accidents would increase, the OPS concludes that the benefit of the proposed rule in eliminatilig deaths, serious injuries, and property damage is on the order of $40 million per year. Consequential Impact of Natural Gas Pipeline Accidents The accident impacts described above are direct effects, i.e., they are caused directly by the pipeline rupture and resulting explosion and fire. The consequences of natural gas transmissic )n pipeline accidents often do not stop there. Other impacts include disruption of business activities in the immediate area of the accident and possibly in areas near the accident. Many communities are served by natural gas distribution companies that receive their produci via single lateral pipelines from a natural gas transmission pipeline (so-called “sole-source lateral j”). If an accident occurs on the transmission pipeline that results in interruption of the flow of nai ural gas, service to customers in communities served by sole-source laterals may be cut off. The ’National Transportation Safety Board, Pipeline Accident Report: Texas Eastern Transmission Corporl (tion Natural Gas Pipeline Explosion and Fire Edison, New Jersey March 23, 1994, January 18, 1995, p. v. 15#

Page 17interruption may be temporary, if gas supply can be restored by valving out the damaged secti In of pipe and re-establishing supply from undamaged portions of the line. Even so, there is bot1 I an economic and a safety consequence to such service interruptions. When natural gas service is cut off, pilot valves on gas appliances go out. Service cannot simply be restored, since gas would enter homes and businesses through the open pilot valves, potentially build to explosive concentrations, and result in fires, explosions and additional collateral dam ige. For this reason, restoration of natural gas service requires that local distribution companies fo low labor-intensive procedures. Representatives of the distribution company must enter each busi less or residence to which service was interrupted. They must close valves to pilot lights. Distribi ttion mains and laterals must be purged to eliminate air that may have become entrained. Only the n can service be restored. Restoration of service again requires that an employee of the distribution operator must enter he premises, reopen pilot light valves, and re-light the pilot lights. This process can take several days. A recent service outage involved loss of natural gas service to approximately 4500 customers. Service was restored in 48 hours, but only by the efforts of 400 personnel, many supplied by other local distribution companies to assist in the emergency recovery effort. Economic consequences included business interruption for the period of the outage, overtime for local operator personnel, and the need for the local operator to house and feed personnel loant'd from other operators to assist. For purposes of illustration, if we estimate the labor costs of th 3se 400 personnel at $75 per hour and they worked 24 hours (2 twelve hour days) the labor cost a one would be $360,000. Additional costs would include transportation, leased emergency equiprr ent, lost revenue from the customers who were not served. It is easy to imagine how the cost of SL ch an accident on a small line with only 4500 customers could easily approach $1-2 million. There is a potential that the impact of consequential damages from service interruptions could grow. Natural gas is currently being used to power many new electrical generating facilities. As more of the nation's electricity is generated from natural gas, the supply of electricity will alsc become more dependent on reliable, continuous availability of natural gas. It is possible that future accidents on major interstate natural gas transmission pipelines in certain areas could rc sult in loss of natural gas supply to multiple electrical generating stations. Electricity generators typically have a supply margin to account for the unexpected loss of a generating facility. If tc )o many generators are lost simultaneously, however, the margin can be overwhelmed and electr cal blackouts, with their attendant consequences, could result. Public Confidence The most significant benefit of the proposed rule is less tangible. It will provide a basis for improved public confidence in pipeline safety. Public confidence has been shaken as a result '2f several recent accidents with significant consequences. These accidents were widely reported by national media, becoming known well beyond the communities in which they occurred. Thes ; included the 1994 pipeline rupture, explosion, and fire at Edison Township, NJ (discussed ab( we), a June 10, 1999, rupture of a hazardous liquid pipeline in Bellingham, WA, with subsequent fire, 16 . . . . . . . . - .#

Page 18and an August 19,2000, natural gas pipeline rupture, explosion and fire near Carlsbad, NM. Three persons were killed in the Bellingham accident. Twelve persons were killed in the Carl sbad accident. (Hazardous liquid pipelines, such as the one involved in the Bellingham accident, would not be affected by this proposed rule. They are covered by similar rules for hazardous liquid pipelines, which have already become effective.) Improving public confidence is, in itself, important. It will, however, also result in economic benefits. One way in which public concern regarding pipeline safety manifests itself is in increased put lic opposition to new pipelines. Local governments can impose additional requirements and restrictions that delay construction and result in significant additional costs. A recent examplc : involved the conversion of an existing hazardous liquid pipeline in Texas. Community reactic In in the city of Austin resulted in delays and significant additional costs. In response to the community reaction, the operator replaced 12 miles of the existing pipeline with 21 miles that looped to the south of the city, avoiding most populated areas. This significantly increased th ; cost of the pipeline project. According to data published in the Oil and Gas Journal, the costs of constructing pipeline have increased significantly over the last 15 years. The average cost of constructing on-shore natural gas transmission pipelines between 1995 and 2000 was $1.12 million per mile. A similar re-route for a natural gas transmission pipeline thus would have C I )st approximately $23.5 million. Increased public opposition can also result in delays in implementing pipeline projects. In SOI ne cases, the related costs associated with responding to public concerns, participation in public hearings, and financing of major construction projects during delays can be as significant as, clr more than, the cost of installing new pipeline. In the extreme, increasing public concern coulc I make it impossible to site and construct new natural gas transmission pipelines. The United States needs additional natural gas transmission pipeline capacity to meet current md future needs. FERC approved 2,449 miles of new transmission pipeline in 2001.'0 If operatos are unable to construct new pipelines, the existing pipeline system would rapidly reach its capacity limit. New applications of natural gas as a fuel would need to be foregone. The abil ty to use natural gas as an environmentally-preferable fuel for new electric generating capacity would be lost. Curtailment of existing natural gas usage would likely be required. For all of 1 hese reasons, it is vitally important that the public have confidence that the national network of nat iral gas transmission pipelines is safe. The proposed rule provides a foundation for an improvement in public confidence. It would require operators to implement inspection and assessment programs directed at identifying thc causes of the major pipeline accidents summarized above, and other potential causes of pipeli le accidents, and correcting them before pipeline accidents can occur. The resulting increase in "Federal Energy Regulatory Commission, 2001 Annual Report, p.24 17#

Page 19public confidence of pipeline safety may well result in less opposition to new pipelines, faster permitting, and less delay caused by local government efforts to require additional provisions 3r re-routing to improve safety. Preventive Maintenance vs. Accident Response The proposed rule would require operators to implement programs that are intended to identify’ areas on their pipelines needing remediation and repair and to accomplish the necessary remediation and repair efforts. If not found and repaired, some of the anomalies could cause accidents, and thus require repair (and recovery activities). The proposed rule can thus be seen, in part, to be a substitution of “preventive maintenance” (Le., identify problems early and addres j them) for reactive response to accidents. The proposed rule includes schedules by which required remediation actions must be taken, which vary depending on the severity of the identified anomalies. Operators would be permitted to t ike longer than these schedules if they provide additional margin of safety by reducing pressure o they notify the OPS of the circumstances requiring additional time (which will allow the OPS to review those circumstances and oversee the operator’s actions). Remediation of identified anomalies is thus more in the nature of preventive maintenance: operators can schedule their efforts based on important factors such as availability of repair resources and when demand 01 1 the pipeline is relatively reduced. If the line must be taken out of service for the repairs, advancec I preparations can avoid the need for service interruptions and their consequences (as described above). Not identifying and resolving these anomalies could cause some of them to result in accidents, Then, operators have no flexibility. Repair resources must be made immediately available, regardless of other demands. Overtime and use of “borrowed” crews from other pipeline operators is almost always involved. In addition, the accident may cause additional damage tc I the pipeline involved or to other pipelines on the same right-of-way. Damaged pipelines may be )ut of service for extended periods. Informal discussions with natural gas transmission pipeline operators indicate that typical cos s to repair defects found by inspection range from about $20,000 to $60,000, depending on whethl :r service must be interrupted to effect the repair. The cost of unplanned recovery from a leak c; in be up to an order of magnitude higher. The cost of recovering from a major pipe failure can 0 e two or more orders of magnitude higher, i.e., in excess of $5 million. Costs to the operator to repair the damage caused directly by the Carlsbad accident amounted to approximately $1 million. Indirect damage caused by the accident resulted in approximately ; ,n additional $4 million in costs. Repairs and modifications necessary to retum the pipeline to service cost an additional $3 million. Perhaps most important, the pipeline was out of service for a total of 324 days after the accident. Even then, the line was returned to service, pursuant to requirements imposed by the OPS, at reduced pressure. Pressure was increased in steps as additional inspections were performed and confidence was gained, but operation at full pre- 18#

Page 20accident pressure did not resume for approximately an additional year. Although this proposed rule would impose actions on operators to develop and implement the programs resulting in the desired “preventive maintenance”, it will help operators avoid the significant additional costs that would result if anomalies were not identified and repaired and accidents resulted. Consideration of Increases in Operating Pressure Pipeline safety regulations presently limit pipeline operating pressures in order to limit stresse s in the pipe, thus providing a safety margin. The allowable pressure is based on the pressure at u hich the pipe has been tested, which is, itself, determined by the ultimate strength of the pipe. In n ral areas, pipelines are allowed to operate at pressures that induce stresses in the pipe wall equal 1 o 80 percent of those that have been demonstrated acceptable by pressure test. In class 3 and 4 are, is, which would be included among high consequence areas under the proposed rule, the corresponding limits are 66.7 and 55.5 percent respectively”. The reason for these lower limits has been to provide additional margin against accidents in areas where the population near thc pipeline is higher. The margin is, in part, to account for unknown problems and pipe degrada ion that could result in accidents. This proposed rule would require operators to inspect natural gas transmission piping in class 3 and 4 areas. Anomalies that could threaten pipe integrity will be identified and appropriate remedial actions will be taken. This will improve knowledge of the condition of the pipe and reduce the need for additional margin in the form of lower stresses in the pipe wall. Accordin gly, this proposed rule could provide a basis under which the OPS could approve operation of sou e natural gas transmission pipelines in class 3 and 4 areas at higher pressures than are presently allowed. (The particular circumstances of each area would be taken into account in deciding whether operation at increased pressures is acceptable). The OPS has some experience in granting such approvals. Operators who participated in the <isk Management Demonstration Program (RMDP) implemented various activities to improve the r knowledge of the factors causing risk on their pipelines and to address those factors. Many ol the activities implemented were similar to elements that will be required in integrity management programs required by the proposed rule. Natural gas pipeline operators participating in FWD were granted authority to implement risk management alternatives in lieu of reducing pressun or replacing pipe in areas where population growth had resulted in a change in class location. TI ie effect was operation of the pipe at a higher pressure than otherwise would be required by 49 C FR 192.61 1 on the basis of the improved knowledge of, and control over, risk in those areas. Ma ure integrity management programs, addressing risks in high consequence areas could provide a b asis for authorizing operation at higher pressures in the same manner as did FWDP altematives. “49 CFR 192.61 l(a)( 1) 19#

Page 21For a natural gas transmission pipeline, increased operating pressure results in additional throughput, i.e., delivery of larger quantities of gas without need to replace the pipe with one (If larger diameter. The possibility of operating pipelines at higher pressures thus affords operatc rs the opportunity to increase natural gas deliveries from the existing pipeline infrastructure. Th s could obviate or delay the need for some new pipelines. It would also increase the availabilitj of natural gas to meet all of the needs described earlier. Informal discussions with pipeline oper;'tors have indicated that the increased gas deliveries that would result from an increase in pressure associated with a ten percent increase in allowable pipe wall stresses would more than offset t le costs of complying with the proposed requirements, including the costs required to make a lin : piggable. Improvements in Pipeline Testing Technolom This proposed rule will provide a spur to development of new and improved methods of pipellne inspection. Internal inspection of natural gas pipelines has heretofore not been required. Some operators have implemented voluntary testing programs. This proposed rule, and its companil )n rules for hazardous liquid pipelines, would significantly increase the demand for internal pipe ine inspection services. This demand will be long term and reliable, since the proposed rule requj res periodic re-inspection. (Voluntary programs might not have resulted in re-inspection of pipel! nes or in re-inspection at longer intervals). In the short term, growth is expected among the companies providing inspection services for natural gas transmission pipeline operators. In th e longer term, increased competition to provide these services can be expected. The relatively improved economic position of inspection services companies will allow them ' 0 invest in research to improve their inspection technology. Improved technologies might be ah le to detect anomalies that can not now be identified by internal inspection. Research might be abl' ; to improve or develop new techniques to evaluate pipe using direct assessment. Improved methc )ds may allow inspections to be done more efficiently, at reduced cost to operators and with less interruption to natural gas service. Inspection companies will have an incentive to develop thl :se improvements in order to improve their ability to obtain contracts from pipeline operators to conduct inspections. Society will benefit from improvements in inspection technology through the safer pipe that P ill result from identifying and remediating anomalies that can not now be addressed. Summary of Benefits The benefits that will result from implementation of the proposed regulatory requirements are summarized in Exhibit 1. 20#

Page 22Exhibit 1. Summary of Expected Benefits Reduced death and serious injury and reduced property damage (combined, on the order of $40 milliodyear) Improved basis for public confidence in pipeline safety, e.g. improved ability to site and construct new pipelines Reduced consequential damages from unexpected interruption of natural gas service I Facilitate consideration of increases in operating pressure I I Foster improvements in pipeline testing technology I COSTS The proposed rule requires that operators, within one year of the effective date of the final rulc :: (1) identify pipeline segments that could affect high consequence areas, (2) prepare a written plan for initial (or baseline) assessment of all pipeline that could affect a high consequence area, and (3) prepare a framework addressing each element of an integrity management plan for their pipelines. These documents will detail testing methods to be used, risk factors considered in the selectioii of the appropriate testing methods for each particular high consequence area, and the schedule 0: ' testing and inspection. Appropriate testing methods include: (1) pressure testing, (2) internal inspection, (3) direct assessment, (4) equivalent altematives (in terms of knowledge of the pipeline provided), and ( 5 ) confirmatory direct assessment (for those segments for which regular assessments are conducted on intervals greater than seven years). Once the plans have been prepared they will be used for baseline integrity testing. That testing must be completed within ten years of the effective date of the final rule, seven years if the assessment method is direct assessment. (Half of the testing must be completed within the fi st half of the required period, and the baseline testing period may be extended, to 13 or 10 years. for medium consequence areas). OPS inspections will verify the plans and assure they are implemented thoroughly. Pipeline operators would be required under the proposed rule to retest their pipeline mileage i 1 or 21#

Page 23near high consequence areas periodically. Assessments of some type must be conducted no le 3s frequently than once each seven years. Full retests must be conducted for most pipe at least 01 ice every ten years (five years if the test method is direct assessment and all anomalies are not excavated) depending on risk factors. The required interval for h l l retests is extended to 15 y :ars for piping operating at less than 50 percent of specified minimum yield strength (SMYS). Pipeline in class 4 areas must operate at 50 percent SMYS or less. Based on the 2001 annual reports of gas transmission pipeline operators, as discussed above, 1,577 miles of natural gas transmission pipeline is in class 4 areas, of which 203 miles is estimated to be intrastate pipeline in Texas. A total of 1,375 miles of transmission pipeline in class 4 areas will thus be required to retest at 15 year intervals. In addition, some class 3 pipelines operate at less than 50 percent SMYS. OPS does not colle :t data regarding how much natural gas transmission pipeline operates below 50 percent SMYS, and thus does not know how much class 3 piping operates below this level. OPS notes, however, hat transmission pipelines operated by Local Distribution Companies (LDC) almost always opera e at less than 50 percent SMYS. The American Gas Association and American Public Gas Association, which together represent most U.S. LDCs have submitted comments on this doc1 et estimating that their members operate approximately 16,500 miles of transmission pipeline in class 3 and 4 areas. For purposes of this analysis, the OPS has therefore assumed that an additional 15, 500 miles of class 3 transmission pipeline (their 16,500 mile estimate for classes 3 and 4 reduced to recognize that a majority of the known class 4 mileage is likely operated by LDCs) operates at pressures that will require retesting every 15 years. OPS has assumed in this analysis that all other class 3 piping and all the additional affected pipeline not in class 3 or cl LSS 4 that is assessed with in-line inspection or hydrostatic testing will require full retest every 10 y' :as. Pipeline operators would also be required to evaluate their pipeline segments that can affect h gh consequence areas to determine whether installation of automatic shutoff valves or remotely controlled valves is necessary to reduce risk. Operators would be required to install such valv 2s where they are found necessary. Based on the foregoing requirements, the costs that can be expected to result from the regulatc ~ry change will be those associated with the major provisions of this rule, which are: 1. Identifying pipeline segments that can affect high and medium consequence areas 2. Framework - setting up integrity management program; 3. Baseline assessment - intemal inspection, pressure testing, or direct assessment; 4. Periodic assessment (inspection) & evaluation; 5 . Evaluating automatic shutoff and remotely controlled valves; 6. Data integration; and 7. Remedial action. The Costs of Identifying Pipeline Segments that Can Affect High Consequence Areas 22#

Page 24Natural and other gas transmission pipeline operators are currently required to monitor the population along their pipeline. The number of occupied dwellings in a sliding mile within 6t 0 feet of the pipeline has been the basis for determining the “class” of the pipeline for many yea: s. The definition of high consequence areas for natural gas pipelines builds off this existing knowledge, starting with the portions of the pipeline that are class 3 and class 4. This informa tion should already be known to the operators, and there is therefore no cost in identifying class 3 md class 4 areas as a result of this proposed rule. (Some local distribution company - LDC - operators treat all of their piping as though it were class 3 or 4 rather than performing the population monitoring that would be required to detern ine the specific class location of a particular segment of pipe. This approach will also be acceptat le for the proposed rule, although all requirements of the rule would then apply to all of the company’s transmission piping. OPS presumes that LDC operators following this approach a so reported all of their transmission piping mileage as class 3 or 4 in their 2001 annual reports. S ince this analysis bases its estimate of the affected mileage on those reports, the entire transmissior mileage operated by LDCs taking this approach is included in this analysis). High consequence areas for natural gas transmission pipelines involve more than just class 3 i nd class 4, however. The additional factors include the presence of buildings housing people wit 1 limited mobility and places where people congregate in proximity to the pipeline. Some of th, :se locations may exist outside current class 3/4 locations. Operators will need to conduct additic nal surveys of the areas near their pipeline to determine if there are any such areas that require additional pipe to be classified as being able to affect a high consequence area. The area of interest is also expanded for pipelines over 30 inches in diameter and operating at a pressure of greater than 1000 psig. For these pipelines, the area in which population density or location of structures/areas of special interest must be evaluated is within 1000 feet of the pipeline. The area of interest may even be greater than 1000 feet if a calculation of potential impact radius indicates a likely effect beyond that distance for a postulated pipeline rupture ar d explosion. In locations where the area of interest is greater than 660 feet, operators will also r eed to determine if any circle of 1000 ft. radius (or larger for some large-diameter, high-pressure pipelines) centered on the pipeline includes 20 or more buildings intended for human occupar cy, a population density equivalent to that of class 3. Some operators may have information regarding this expanded area, since much of it is immediately adjacent to the area about which current regulations already require them to collc ct information. Since there is no requirement for operators to gather information about this expanded area, this analysis assumes that operators will need to gather additional information to determine whether the numbers of people housed or the existence of structures/areas of intere ;t (as included in the definition of high consequence areas) requires classification of a pipeline segment as having the ability to affect a high consequence area. There are 668 natural gas transmission pipeline operators who could potentially be subject to he proposed rule, based upon annual reports submitted for 2000. Some of these operators operat ? 23#

Page 25very little transmission pipeline mileage. Specifically, 275 operators have less than 20 miles c f transmission pipeline. An additional 97 operators have between 20 and 39 miles of such pipe1 he. The cost for collecting new information to identify pipe segments that can affect high consequence areas (as well as costs for implementing other elements of the proposed rule) will be considerably less for these 372 operators. (Some of the operators with small amounts of transmission piping are LDCs that treat their entire systems as class 3 or 4. If they continue th at practice, then they will incur no costs for identifying high consequence areas; all of their syste ns will be treated as though they are high consequence areas. Nevertheless, this analysis has conservatively assumed that all affected operators will need to identify high consequence area ;). The effort to collect additional information and determine whether additional segments of pip! :line (i.e., beyond those already identified as class 3 or class 4) can affect a high population area represents principally a manpower cost. The costs are expected to be moderate, because each operator must already have programs in place to collect periodically information on the areas 1 n proximity to their pipeline. This proposed rule simply expands the area. The OPS estimates that the cost to operators with significant amounts of pipeline mileage will be less than one half of a staff year, or $60,000.'* The information collection activity is expected to be much smaller foi- operators with only a few miles of pipeline, and is estimated at $15,O0Oi3 for the 372 operator:, with less than 40 miles of pipeline. Based on the foregoing, the total cost estimated for operator identification of pipeline segmenl s that can affect HCAs is $23.34 million. This is a one-time cost. Maintaining and updating th s information after the initial segment identification is expected to be accommodated within the operator's existing program for monitoring the pipeline for class locations. The Costs of Plans and Reports The single most important part of this proposed rule is the requirement for the integrity plan a id framework. The creation, development and implementation of these documents will provide f ir the necessary integration of information regarding pipeline condition. Integration is importan to assure the OPS, and the public, that pipeline operators are considering fully the unique risks tl [at gas transmission pipelines pose to high consequence areas. Plan development will assure not only that they are considering these risks but that they have developed a plan that requires extra scrutiny and precautions in these areas to safeguard the public. These safeguards include the 1 ise of periodic testing. Since integrity management programs are not universal across the industry, the OPS believes hat a requirement that such plans be developed is necessary. The proposed rule requires that plan ; be '*Assumes annual salary of a senior engineedsupervisor of $90,000 with a multiplier of 1.33 to include benefits for a staff-year cost of $120,000. One-half of this is $60,000. I3It is assumed that identification of segments that can affect high consequence areas along less than 40 miles of pipeline will require approximately one to two man-months. The assumed $120,000 cost of a staff-year is divided by 12 to yield $10,000 per month. A point estimate representing one and one-half man months is then u ed. 24#

Page 26developed and specifies considerations that must be taken into account in that development. Development of the plans will involve consideration of risk factors unique to particular pipelii ies and high consequence areas. Operators will be required to establish a periodic assessment program in which all segments in high consequence areas are assessed at least every seven ye: rs and are pressure tested or internally inspected no less frequently than once every ten or fifteen years, depending on operating stress levels, unless an exception is justified. (Pipe evaluated b direct assessment would be required to be reassessed no less frequently than once every five y :an, unless all identified anomalies are excavated). These frequencies may be extended for mediur 2 consequence areas as defined in the proposed rule. Evaluation is an ongoing process. Operators will be expected to consider the risk factors and heir relative priorities in establishing assessment schedules. This allows operators to develop an intemal inspection and testing program that is customized to the particular operating characteristics and risks associated with different portions of their system(s). The plans and reports required by the proposed 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, (3) providing real-time access t,J program performance measures for OPS and state pipeline safety inspection offices, and (4) 0’ her 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. Such plans were required of hazardoi is liquid pipeline operators through regulations promulgated in 2000 and 2001. The deadlines u ider those rules for developing the plans are only now arising, or are still in the hture. The OPS therefore has no data on the cost to hazardous liquid pipeline operators for development of tht required plans. Informal discussions with pipeline industry consultants indicate that these pla is can cost anywhere from $75 thousand to $300 thousand. Well over half their cost would be expected to go toward the preparation of the plan (Le., analysis and writing). 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. The 0 ’S does not expect that plans developed solely to meet the requirements of this rule will be as C O I ,tly to develop as these more extensive plans. The OPS also notes that the plans required of oper: tors with only a few miles of pipeline will be simpler than an “average” integrity management plai I for a large operator. For the purposes of this analysis, it is assumed that a written plan and framework prepared by a pipeline operator with substantial gas transmission pipeline mileage and developed solely to 25#

Page 27comply with this rule will cost $200,000.'4 This value was derived by assuming that costs for more comprehensive plans would be near the upper end of the estimated range of costs for ne1 v' pipeline integrity management plans. Since costs for plans developed solely to meet the requirements of the rule are assumed to be lower, a cost in the upper half of the estimated rani e, but below the maximum, was used. It is assumed that a written plan and framework prepared by a pipeline operator with less than 40 miles of pipeline solely to comply with this rule will cost $125,00015, within the lower half of the estimated range. The OPS notes that costs could be considerably lower for operators with on1 a few miles of pipeline or a limited number of pipeline segments that can affect high consequen :e areas (separate locations that must be considered). The OPS has not attempted to determine h IW many of the operators with less than 40 miles of pipeline fall into this category and has, instea j. conservatively used the same cost estimate for all operators potentially subject 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 inspectioii technology, and changes to the pipeline system or its operation. 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 place. The OPS has estimated this annual effort at $16,000 per year. It is expected that the supporting documents that will be created will be primarily record keep ng 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 sta ff at the pipeline, under the oversight and management of senior staff. They are expected to take n I longer than two labor weeks to produce. It is estimated that they will have a total cost of $4,0 IOi6 For the purposes of this analysis, it is assumed that these reports will be produced annually. Here again, the OPS considers that costs for operators with only a few miles of pipeline in a limited number of locations will be lower, but has conservatively assumed these costs for all l4This value compares with an estimate of $100,000 for preparation of integrity management plans usec in the regulatory analysis for the companion rule affecting operators of more than 500 miles of hazardous liquid pipelines. Those operators are only now completing their plans. OPS interaction with hazardous liquid pipeline operators has led us to conclude that these costs may have been underestimated, and a change has thus been mad : in this analysis. I5This value compares with an estimate of $75,000 for preparation of integrity management plans used n the regulatory analysis for the companion rule affecting operators of less than 500 miles of hazardous liquid pipelines. Here again, it is assumed that it will be cheaper to develop plans for systems with small amounts of transmission piping, but the estimate has been increased due to the feedback that costs were underestimated for t le hazardous liquid pipeline rules. I6These values, $16,000 and $4,000, are twice those assumed for the corresponding hnctions in the regulatory analyses for both rules affecting hazardous liquid pipeline operators. 26#

Page 28operators subject to the proposed rule. Costs of Real-Time Access to Performance Measures The proposed rule requires that an operator include in its integrity management program methi )ds to measure whether the program is effective in assessing and evaluating the integrity of pipelir e segments and in protecting high consequence areas. The measures must include those specific d in an industry standard, ASME/ANSI B3 1.8s. The proposed rule would require that operators rr ake these performance measures available to OPS and state pipeline safety enforcement offices in “real time”. The performance measures specified in ASME/ANSI B3 1.8s involve tabulations of relevant parameters. These include number of miles of pipeline inspected, number of hydrostatic test failures, number of immediate repairs completed, number of scheduled repairs completed, and number of leaks/failures/incidents experienced (classified by cause). They are not parameters that vary continuously. Rather, they increment upon the occurrence of specific events (e.g., tests, repairs, failures). Maintaining these performance measures will require updating a tabulation i s the events occur. This activity is considered part of routine record keeping as described under “other supporting documents”. The nature of these performance measures makes it virtually certain that operators will mainta in them in some sort of spreadsheet. The OPS assumes that all pipeline operators will use a computer to maintain this information. In this context, therefore, providing “real time” access to the performance measures for OPS and state pipeline safety enforcement offices requires only a means for OPS and state inspectors to access the spreadsheet. There are two ways such accesi could be provided: via a web site, or via a dial-up modem connection. In either case, operators will likely want the information to be treated as confidential, not avai able for release to the general public. Electronic security will thus be needed. For web site access, this will involve establishing password protection for a page containing the information that must >e made available. Firewalls may also need to be established to separate that information from o :her information that an operator may not want OPS/state inspectors to access. For dial-up access, again password protection and segregation from information the operator does not want to ma <e available will be needed. The OPS assumes that operators who already have web sites will most likely utilize those site ; to provide the required access to this information. There will be no costs associated with establishing the web sites, only with modifying them to display the required information and provide the necessary security. Operators with web sites will also have some type of web programming capability, whether by an internal Information Technology (IT) department or a 1 outside consultant in web site management. A qualified web programmer would likely be ab1 3 to make the changes necessary to provide secure, isolated access for OPS and state pipeline inspection offices in a matter of a day or two. The cost for establishing web access to the reqi ired 27#

Page 29performance parameters thus would be on the order of $550”. Operators that do not have web sites are still likely to use networked computers to manage an( i store information associated with their integrity management programs, including performanc ; measures. OPS assumes that these computer networks will already be equipped with modems, since they are standard features of modem computer systems. OPS also assumes that operatoi s will have the ability to provide secure, password-protected access to their networks easily, sin1 :e this is the process usually used to allow company employees to access the computer network when they are away from their offices. Establishing password-protected access for OPS and s’,ate pipeline safety inspection offices should thus involve minimal cost. In-house or contracted IT support would be required to establish the necessary security separation to allow OPS/state ac :ess to the required performance measures while precluding access to information the operator doe s not intend to share with the regulator. Again, it is assumed that the necessary programming c;ln be performed in a maximum of 2 days at a cost of approximately $550. Operators who do not have web sites may elect to set up a web site to provide the required acc ess to OPS and state pipeline safety inspectors. Costs for initial development of a web site could >e higher than these estimates. The cost of web site development is not considered in this analys LS, however, since the proposed rule would not require that the web be used as the access vehicle Operators who do not have computer systems, if any, or operators desiring not to provide any access to their computer networks for OPS/states could purchase a separate computer to be us :d solely to post performance measures for OPS/state availability. Programming would not be required to provide security, since the separate computer would not be connected to any computers including information to which the operator did not want OPS/states to have accesi I. A very basic computer could be used, since virtually no calculational capability and limited men lory capacity would be required to post a performance measures spreadsheet. OPS does not expec that many, or any, operators will use this method of providing the required access. Here, agai 1, however, the costs would be on the order of several hundred dollars, the cost of a basic compi ter equipped with little more than a modem. The OPS thus concludes that providing “real time” access to performance measures, as requir :d by the proposed rule will cost all operators approximately $550. The total cost to the 668 operators potentially affected by the proposed rule is thus $367,400. These costs are assumed to be incurred in the first year after the effective date of the proposed rule. Total Cost of Plans and Reports There are 668 natural gas transmission pipeline operators who could potentially be subject to he proposed regulatory change. Three hundred seventy-two of these companies operate less thar 40 I7Assumes programmer salary of $50,000 annually, multiplied by 1.33 to account for cost of benefits, divided by 1920 to produce an effective hourly rate, and multiplied by 16 to obtain the cost for two days work: $554.17. 28#

Page 30miles of pipeline. Some of these operate only a few miles of pipeline and may have no pipeliI e that would affect a high consequence area. Such companies would not be subject to the propc sed rule. The OPS does not yet know whether any operators have no pipe that could affect a high consequence area, and has conservatively assumed that all 668 operators will be affected. Each of those operators will need to perform annual documentation and updates. The cost of these activities is conservatively estimated to be $13.36 million per year. The Office of Pipeline Safety expects that some of the larger operators of natural gas transmision pipelines have already developed integrity management plans that will meet or exceed the requirements of the rule. For purposes of this analysis, the OPS assumes that 25 percent of th : operators with more than 40 miles of pipeline have already developed integrity management plans at least sufficient to comply with the proposed rule. The OPS expects that the remaining 75 percent of operators with more than 40 miles of pipeline will need to develop plans (costing $200,000 each) and that all of the operators with less than 40 miles of pipeline will need to develop plans (costing $125,000 each). In addition, all affected operators will need to providt real-time access to performance measures (total cost $367,400). These costs will only be incurred once. Based on the foregoing, the total cost for plans and reports will consist of a one-time cost of $31.3 million plus an annual cost of $13.36 million." Inspection and Testing The proposed regulatory change requires baseline and subsequent testing of the impacted mile age using in-line inspection, pressure testing, direct assessment, or alternative methods. Acceptab le in-line inspection includes high resolution, low resolution, and ultrasonic pigging. Acceptablc : pressure testing consists of hydrostatic testing. Acceptable techniques for direct assessment a .e as described in an industry consensus standard. Acceptable alternative methods include any othc r methods that would provide a level of safety equivalent to that provided by the specified methods. In addition, a more focused application of direct assessment, confirmatory direct assessment, would be required for pipeline segments that would be assessed using one of the other methoc s at intervals greater than seven years. Internal inspection (pigging) requires that an instrument (pig) be inserted into a pipeline, trave 1 through the line, and be removed. The points at which the pig is inserted and removed are referred to as launchers and receivers. These are usually permanent installations, and are ofte: 1 located at compressor stations. An individual pig inspection thus covers an amount of pipelin E mileage roughly equal to the spacing between compressor stations, which is typically about 5(1 miles. ''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. 29#

Page 31Baseline Testing The proposed rule requires that baseline testing be completed within ten years of the effective date of the rule if the chosen assessment method is pigging or hydrostatic testing. (Baseline testink can take 13 years for pipe segments affecting medium consequence areas. OPS has not considerec I this more relaxed schedule in this analysis and has conservatively assumed that all affected PI pe must be tested within 10 years). Baseline testing must be completed within 7 years if direct assessment is the chosen method. (Baseline testing by direct assessment must be completed ii i 10 years for pipe segments that can affect medium conseqeunce areas but, again, OPS has conservatively assumed all pipe subject to direct assessment must be assessed in 7 years). As noted above, at least some gas transmission pipeline operators currently have integrity management programs that include some testing. It is therefore likely that some of the affecte d mileage would be tested even if the proposed rule were not promulgated. The Interstate Natural Gas Association of America (INGAA) has estimated that 25 percent of the natural gas transmission pipeline system has been pigged since inspection devices became generally available in 1980.19 This testing did not occur at a constant rate over that period. Rather, pigging was conducted sparingly in the early 1980s and the amount of pipeline piggin ; being performed has increased in recent years. For purposes of this analysis the OPS assumes that the current rate of pigging for natural gas transmission pipelines would inspect 25 percent of tlie transmission piping in approximately 10 years, or 2.5 percent per year. The definition of high consequence areas makes it unlikely that these areas will occur uniforn ly throughout the natural gas transmission pipeline network. Rather, they would be expected to )e concentrated in areas with higher population, and to occur much less often in rural areas. Thii I means that it is possible that a pig inspection conducted in a rural area could inspect 50 miles sf pipeline and not inspect any pipe segment that could affect a high consequence area. It is like y that some pigging being conducted today is in such rural areas. As a result, it would be unreasonable to assume that 2.5 percent of the pipeline that can affect high consequence areas would be inspected each year if the proposed rule were not promulgated. For purposes of this analysis, the OPS assumes that 1.5 percent of the pipeline in high consequence areas would bt pigged each year under current industry practices and that this rate of pigging would continue if the proposed rule did not become effective. The OPS invites comment on the actual amount of transmission pipeline testing in high consequence areas that would occur in the absence of the rule. Subsequent Testing Once baseline testing has been performed on a segment of pipe, the rule requires that subsequ :nt 19,' Consumer Effects of the Anticipated Integrity Rule for High Consequence Areas," prepared for the INGAA Foundation, Inc. by Energy and Environmental Analysis, Inc., 2002 30#

Page 32testing be undertaken on that segment. Some type of assessment, at a minimum application o ’ confirmatory direct assessment, must be conducted on all affected pipe segments at least eve? r seven years. Testing using one of the other accepted methods must be performed, based on ri: k factors, at least once every ten years (with limited exceptions). The full retesting interval is 1 t years for pipe operating at less than 50 percent SMYS, and OPS has estimated the amount of transmission pipeline mileage that will be subject to this longer re-assessment interval as described above. The required retesting interval is five years if the assessment method used i: direct assessment and all anomalies are not verified by excavation. The planned rate of re-testing of pipeline by operators if this rule is not promulgated is unknoi vn. Some operators currently have programs under which pipe is tested periodically. It is also likc :ly that some pipe being tested for the first time might never be reinspected absent this proposed 1 ule. The OPS has estimated that testing would continue indefinitely at the present rate, i.e., 1.5 peI zent of mileage that can affect high consequence areas would be inspected by pigging annually. TI le OPS has assumed that no re-testing by hydrostatic tests or direct assessment would be perforn ed without the requirements of the rule. Operators will need to do some subsequent testing at the same time they are doing baseline testing. This will occur for piping that is assessed using direct assessment. Baseline assessmc nts performed using direct assessment must be completed within seven years of the effective date of the final rule. Re-assessments of piping assessed using direct assessment must be conducted : t least every five years (unless all indications are excavated or examined). This means that operators will need to re-assess in the sixth year pipeline segments assessed in the first year u: ing direct assessment. Costs will therefore be incurred for both baseline assessments and re- assessments using direct assessment in years six and seven. Focused assessments, using confirmatory direct assessment, will also be required in years eight, nine, and ten, while pipin, ; is still undergoing baseline testing using pressure testing or in-line inspection. All of these cost: are considered attributable to this proposed rule, since this analysis assumes that none of the pipkg to be assessed using direct assessment would have been assessed at all absent the rule’s requiren ents and that confirmatory direct assessment would not be used absent this rule. The Costs of Testing For the purposes of this analysis, it is assumed that all required testing will be accomplished 1: y either (1) hydrostatic testing (pressure testing), (2) smart pigging (internal inspection), (3) dir :ct assessment, or (4) confirmatory direct assessment (for interim retesting of those pipeline segn ents tested using one of the other methods on intervals exceeding seven years). Alternative metho( 1s are not yet to the point where their costs for pipeline testing can be reliably estimated. Hydrostatic Testing The total cost of hydrostatic testing has been previously estimated by the OPS to be $4,656 PE r 31#

Page 33mile in 1990 dollars,*’ which equates to $5,274 per mile in 2001 dollars. The estimate does nc t include the cost of making any repairs to the pipe. The 1990 estimate is based primarily on information obtained by the OPS from various industry sources. Information submitted by the Interstate Natural Gas Association of America (INGAA), the American Gas Association (AGA) and the American Public Gas Association (APGA) estimatc ; costs for hydrotesting that are considerably above this amount. INGAA estimates that these c( lsts approach $30,000 per mile. AGA, most of whose members operate in highly urbanized areas, estimates that hydrostatic testing costs can be as much as $250,000 per mile. The OPS recognizes that changed circumstances (e.g., new environmental requirements for disposing of test water) could have increased hydrostatic testing costs since the 1990 study. No definitive information is available estimating the amount by which these costs have increased. For purposes of this analysis, the OPS has continued to use its 1990 estimate, adjusted for inflation. The OPS notes that these differences have relatively less effect on the results of this analysis than might be thought, since industry’s belief that costs for this method will be high have led them to predict that very little piping will be assessed using hydrostatic testing. This analysis reflects industry’s prediction that little pipe will be hydrotested. Smart Pinging The total cost of smart pigging has been previously estimated by the OPS to be $2,839 per mil e in 1992 dollars,*’ which equates to $3,210 per mile in 2001 dollars. This estimate does not inclulie the cost of making a pipeline piggable (ie., adding pig launchers and receivers or modifying pipeline that cannot pass instrumented pigs). Much natural gas transmission pipeline is not currently piggable. The Interstate Natural Gas Association of America (INGAA), the American Gas Association (AGA), and the American Public Gas Association (APGA) each submitted comments in response to a June 27,2001, Federal Register Notice (66 FR 343 18) estimating the percentage of transmission mileage operated by their members in class 3/4 areas that couldcould not be pigged. The reported val ies are presented in Exhibit 2. ZoOffice of Pipeline Safety, “49 CFR Part 195 Economic Evaluation, NPRM - Hydrostatic Testing of Certain Hazardous Liquid and Carbon Dioxide Pipelines,” Docket No. PS- 12 1, Notice 1, May 13, 199 1. ”Office of Pipeline Safety, Instrumented Internal Inspection Devices (A Study Mandated by P. L. 100- 561), Research and Special Programs Adrmnistration, November 1992, p. 44. 32#

Page 34Exhibit 2. Piggable Status of Natural Gas Transmission Pipeline (Percentage of mileage in class 3 and class 4 reported by gas industry trade associations) Pipeline Status Easily Piggable INGAA AGA APGA 24.4 12 13 I 25.3 I 10 I Not I I reported I I I 45.9 I 43 I 41 Piggable with extensive retrofit I Not piggable The OPS does not know the reason for the significant difference between the reports of the th ee pipeline industry associations, particularly for pipeline that is “not piggable”. The OPS interp -ets this to be a result of different inherent thresholds in determining what is “easily” piggable or piggable with extensive retrofits. The OPS does not believe that there is such a fundamental difference in design between INGAA-member transmission pipelines and those of APGA members that there should be an order of magnitude difference in the percentage that is not piggable. (The OPS also notes that APGA members operate much less transmission pipeline lhan the members of the other associations. Their comments indicate that APGA members operate some 3000 miles of transmission pipeline in class 3/4 areas). For the purposes of this analysis, the OPS assumes that 20 percent of natural gas transmission pipeline mileage is easily piggable, that 5 percent is not piggable, and that 50 percent could bc made piggable only with extensive retrofits. This leaves 25 percent that could “easily” be ma( le piggable (i.e., with the installation of temporary pig launchers and receivers and temporary removal of some valves). The OPS invites public comment on the reasons for the differences in the percentages reported by the pipeline industry associations and on its use of these values in this analysis. The costs of making natural gas transmission pipeline piggable are presented in Exhibit 3. Tl- e original sources of the costs in Exhibit 3 were submissions by natural gas pipeline operators tc I the U.S. DOT’S Docket No. PS-105; Notice 1 .23 22This category includes pipe that can be made piggable with temporary installation of pig launchers an 1 receivers and temporary removal of some valves 230PS, Instrumented Internal Inspection Devices, November 1992, Appendix B 33#

Page 35Exhibit 3. Costs of Making Pipeline Piggable (1 992 dollars per mile) Install temporary pig traps on lines that can otherwise pass instrumented pigs Install permanent pig traps on lines that can otherwise pass instrumented pigs E p e l i n e s to accommodate pigs [Add temporary pig traps to modified pipelines Add permanent pig traps on modified pipelines $1,922 - $5,000 $4,802 - 12,383 I $8,489 - 23,805 I $1,922 - 10,367 $5,135 - 10,556 Exhibit 4 presents estimated costs for making pipeline piggable. These estimates are the midrsoint of the costs presented in Exhibit 3, converted from 1992 to 2001 dollars per mile. Exhibit 4. Estimated Costs of Making Pipeline Piggable (2001 dollars per mile) Install temporary pig traps on lines that could now accommodate instrumented pigs $3,914 Install permanent pig traps on lines that could now accommodate instrumented pigs Modify pipelines to accommodate pigs and I $27,130 I add permanent pig traps on those pipelines Source: The mid-points of the ranges presented in Exhibit 3 in 2001 dollars. As described above, industry comments at the July 18,2002, meeting of the Technical Pipelir e Safety Standards Committee (TPSSC) indicated that industry plans predominant use of piggir g to assess transmission pipeline in accordance with this proposed rule. Industry’s comments also indicated that costs to modify pipelines to accommodate pigs can be considerably higher than the values in Exhibit 4, but that the lower operational costs and increased information about the pipeline still make pigging a preferred option. Based upon these comments, the OPS has usec a higher estimate in this analysis for the costs to modify hard-to-pig pipeline, some of which wiil be modified to meet the industry’s aggressive pigging plans. Costs to modify hard-to-pig pipelin 2 to accommodate in-line inspection are estimated in this analysis at $40,000 per mile, which is slightly higher than the upper range reported in Exhibit 3, when adjusted for inflation. 34#

Page 36Direct Assessment Direct assessment is a technique that is in the early stages of development for assessing the integrity of line pipe. Industry consensus standards governing the application of direct assess1 lent are only now being approved. The process consists of several steps. The first step is pre-assessment. This involves collection and evaluation of data regarding potential threats to pipeline integrity and their relative risks. Based on this evaluation, locatio is on the pipeline are selected for indirect inspection. Inspection requires use of a minimum oft NO different “tools”. Examples of direct assessment tools include close interval surveys (CIS), di eect current voltage gradient (DCVG), and pipeline current mapper (PCM). The results of the indirect inspections are then used to identify locations for direct examination, excavation of the pipelii ie to permit visual inspection. Each use of direct assessment requires at least one direct exam. Thc final stage in the direct assessment process is post-assessment in which the composite set of d ita (i.e., risk factors identified in pre-assessment and assessment results) are considered to identif r‘ continuing excavation needs, determine if additional assessment technologies are needed, and to establish a re-assessment interval. There is very limited experience at this time from which to estimate the costs of performing d rect assessment on natural gas transmission pipelines. The techniques are only now being developed. The pipeline industry’s direct assessment development and validation team estimates that the :ost will range from approximately $4,600 to 5,000 per mile of pipe examined. Cost estimates submitted by INGAA, AGA, and APGA assume a cost of $15,000 per mile. The OPS does nc ,t know the basis for this higher value, and for this analysis uses the midpoint of the range estim ited by the development and validation team, $4,800 per mile. Confirmatory Direct Assessment Confirmatory direct assessment is a more-focused application of the principles and technique: of direct assessment. This method is concentrated on identifying critical segments of suspected corrosion. The effort involved is less than full application of direct assessment. The OPS has structured the requirements for confirmatory direct assessment in a manner interlded to allow maximum flexibility for operators. Indirect examinations may be performed using 01 ily one, rather than two, tools. Corrosion regions may be larger than for regular direct assessmen1.s. The number of excavations required per region is less. These changes will allow operators to plan and conduct confirmatory direct assessments in a manner that is most cost-effective, Le., iden ifies areas of concern at lowest cost. There is no data available at present regarding the cost to implement confirmatory direct assessment. The flexibility included in these requirements means that costs may vary depend] ng on assumptions the operator makes in planning and conducting these assessments. For purpoi es of this evaluation, the OPS assumes that the cost will be less than, but more than half, that of direct assessment, or $3,000 per mile. Actual costs for many operators may be lower, and the 35#

Page 37total cost estimates in this analysis are thus expected to be conservatively high. Additional Mileage Must Be Tested It is usually not possible to hydrostatically test or pig pipe in high consequence areas without elso testing some adjacent piping. Hydrostatic testing requires valves that can isolate the pipe segn lent being tested. Pigs must be run between available pig launchers and receivers, which are seldo n located immediately adjacent to the boundaries of high consequence areas. Valves are spaced closer together than launchers and receivers, meaning that the amount of additional mileage that must be subjected to hydrostatic tests is less than that which will be pigged. For purposes of this analysis, the OPS has estimated that the amount of additional piping that #will need to be tested using hydrostatic testing in order to complete the required testing in high consequence areas is 25 percent of the amount of piping in the high consequence areas. For pigging, the estimated additional piping to be tested is 200 percent of the amount of piping in he high consequence areas. The estimates of required testing above reflect the amount of pipe th it must be tested due to the requirements of the rule, i.e., the amount that can actually affect higl: consequence areas. The cost estimates that follow are based on totals that are 1.25 times that mileage for hydrostatic testing and 3 times that mileage for pigging. Direct assessment and confirmatory direct assessment, on the other hand, does not require test ,ng any additional piping. Direct assessment methods do not rely on ability to isolate sections oft he pipe, like hydrostatic testing, nor to gain access to the pipe, like pigging. Direct assessment ci n be used to assess discrete lengths of pipeline. For this reason no additional mileage is assume 1 tested when pipe is assessed using direct assessment. The costs estimates that follow are base 1 on the estimated miles requiring testing, as described above. Choice of Assessment Method Informal discussions with pipeline operators suggest that hydrostatic testing is the least prefer .ed method for assessing pipeline integrity. This was confirmed in discussions at the July 18, 200 2, TPSSC meeting. This is at least in part because hydrostatic testing can be destructive, while t le other two methods are not. Hydrostatic testing also usually requires that a line be taken out of service for a longer period than does pigging. (Direct assessment requires limited out-of-sew ce time or curtailment of pipeline capacity). In addition, care must be taken in drylng the pipelinl: subsequent to a hydrostatic test to assure that all moisture is removed. Remaining moisture ci n cause internal corrosion problems and can also lead to operational problems in freezing weath :r. Pigging appears to be the preferred method of assessment for pipeline. As described above, tile per-mile cost for pigging is less than that for direct assessment or hydrostatic testing. INGAA 's response to the OPS's June 27, 2001, Federal Register notice indicated that the percentage of its members piping in class 3 and 4 areas that has been pigged at least once is approximately equ 11 to 36#

Page 38the percentage of their mileage that is easily ~ i g g a b l e ~ ~ , despite the fact that there is currently ‘10 requirement that pigging be performed. The choice between direct assessment and pigging is not so obvious for pipeline that must be modified to be made piggable. Direct assessment has the advantage of requiring little or no interruption in normal operation of the transmission pipeline. It would likely be the method o f choice for assessing those areas where supply interruption can be most problematic (e.g., singie- source laterals supplying small distribution operators). On the other hand, the costs for direct assessment are higher than for pigging, and the proposed rule would require re-assessments t\ rice as frequently if direct assessment is the method used. Finally, while the direct assessment prc cess produces a significant amount of information about the pipeline, pigging still provides operatc 1r.s the most information from actual examination of the pipe wall. The OPS has limited information about the assessment methods that pipeline operators would choose for pipe that is not easily piggable. The INGAA analysis of consumer effects25 consid :rs multiple scenarios with different portions of this piping assessed using each of the three methl )ds. The analysis presents these as sensitivity analyses, but does not indicate a “preferred” combination. Two-thirds of pipeline operators responding to a 1989 Federal Register notice indicated that they would install permanent pig traps if periodic tests were mandatory. The remaining one-third would have installed temporary traps or were undecided.26 Direct assessr tient was not available as an alternative assessment method at the time of this survey. The OPS ha ; no basis to conclude whether the results would change substantially with direct assessment as an available option. While installation of launchers and receivers would increase the cost of bast :line assessments by pigging under the proposed rule, they would allow decreased costs and longer intervals for required re-assessments compared to use of direct assessment. As a result of the above, the OPS assumed for of the preliminary draft analysis discussed with the TPSSC that pigging would be the testing method used on all natural gas transmission pipeline that is easily piggable. The preliminary draft analysis further assumed that two-thirds of the milea ;e that can “easily” be made piggable would be modified by installation of permanent launchers ind receivers (consistent with the response to the 1989 Federal Register notice) and that pigging would be the testing method used on that pipe. This resulted in the assumption that pigging would be used on 36 percent of affected pipeline mileage, and that 16 percent of affected pipe line mileage would require modification. It was also assumed that pipeline mileage that can only 1 le made piggable with substantial retrofits would not be so modified because of the relatively hi1 ,h costs of doing so. 24 INGAA, Subject: Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) {Docket No. RSPA-00-7666; Notice 2}, 110 date, page 45. 25“Consumer Effects of the Anticipated Integrity Rule for High Consequence Areas,” prepared for the INGAA Foundation, Inc. by Energy and Environmental Analysis, Inc., 2002 260ffice of Pipeline Safety, Instrumented Internal Inspection Devices (A Study Mandated by P.L. loo--! 61), Research and Special Programs Administration, November 1992, p. R-12. 37#

Page 39As described earlier, industry comments at the July 18, 2002, TPSSC meeting indicated that r iuch greater reliance would be placed on pigging than reflected in OPS’s preliminary draft analysis. Information provided by INGAA indicated that as much as 70 percent of long-distance piping is likely to be pigged, even though this requires costly modification of some piping. AGNAPG 4 information indicates that smaller percentages of piping belonging to their members will be pigged. The OPS accepts that these comments represent present industry plans. The OPS is not convinced, however, that those plans will not change by the time the proposed rule is finalize4 I and implementation begins. OPS does not want to prejudge the outcome of the validity of dirt ct assessment. Its abilities to detect anomalies will not be known until actual assessments are attempted by operators. Several of the factors described above contribute to this uncertainty. The costs to modify piping can be considerable. High consequence areas outside of class 3 and 4 locations may be widely distributed, such that any piggable segment of pipeline may include ( nly one to a few miles of pipeline that can affect a high consequence area. The OPS is not convir ced that operators will incur the significant costs to modify large runs of piping to assess a limited amount of mileage that could be addressed using direct assessment. Operators may have othe - reasons for modifying piping to permit pigging, but the costs for such voluntary changes shou, d not be attributed to this proposed rule. At the same time, the proposed rule requires that the threats applicable to specific pipeline segments be evaluated, and that the assessment method chosen be capable of addressing those threats. Recent experience indicates that internal corrosion is of increasing importance as a potential threat to natural gas transmission pipeline integrity. Direct assessment methods for internal corrosion are only now beginning to be developed. Pigging is presently the only met1 od for reliably detecting pipeline deterioration resulting from this threat. The requirement that chosen assessment methods be capable of addressing important threats could mean that indusi ry must modify pipelines to accommodate pigs, despite the high costs. The OPS has addressed this conundrum by considering two scenarios for the inspections that would be required to comply with this rule. In the first, referred to as the limited modificatior scenario, pigging is assumed to be used for all pipe that is currently piggable or that can be “easily” modified to be piggable. No hard-to-pig pipe is assumed to be modified under the lir iited modification scenario. The second scenario, referred’to as the pipe modification scenario, assumes that 65 percent of piping that can affect high consequence areas will be assessed usin g pigging. This scenario includes the modification of a considerable extent of hard-to-pig pipe. The costs for each scenario are presented separately. Costs to modi@ the pipe that is easily piggable are estimated at $9,7 16 per mile (see Exhibit 4). Costs to modify hard-to-pig pipe an: estimated at $40,000 per mile. Limited Modijcation Scenario As described above, the OPS has assumed that 20 percent of existing natural gas transmission piping is piggable, 25 percent can be made piggable with relatively simple modifications, and the 38#

Page 40remaining 55 percent is either not piggable or would require extensive modifications to be ma de so. For the limited modification scenario, the OPS has assumed that these percentages apply o piping that can affect high consequence areas, that the 25 percent of such piping that can “eas ly” be modified will be so modified, and that it and the 20 percent that is now piggable will be assessed by pigging. As also described above, additional mileage must be tested in order to assess pipe by pigging. This scenario uses the assumption of 200 percent additional mileage described above. The question of whether, and with what degree of difficulty, this additional piping can be made piggable thus becomes important. Pipe that is piggable will be part of an overall pipe segment that is piggable, and no modifications will be needed. Pipe that can affect a high consequence area and that can easily be modified may, or may not, be part of an overall pipe segment that can easily be modified for pigging. It is possible that son- e hard-to-pig pipe could also exist between the locations at which an operator would need to in:itall pig launchers and receivers. The OPS has no information on which to judge the relative distribution of easy- and hard-to-pig pipe. For purposes of this scenario, the OPS assumes thz t the additional pipe that must be tested in order to pig affected pipe that can easily be modified caIi, itself, easily be modified. This idealized situation may not always exist, but is a reasonable assumption to create a lower-bound estimate for the modification costs that will need to be incurred to comply with this rule. The assumption that 45 percent of affected mileage will be pigged leaves 55 percent to be assessed using other alternatives. For this scenario, the OPS has assumed that 10 percent of affected mileage will be hydrotested and the remaining 45 percent will be assessed using direc,t assessment. This assumption reflects industry comments indicating that hydrostatic testing is strongly disfavored. Mileage Tested Per Year - Limited Modification Scenario Estimating costs requires determining how much transmission pipeline mileage will be tested each year. This requires an estimate of the reassessment periodicity for individual pipeline segments that are subject to the rule. The rule requires that baseline assessments be conducted over a ten-year period and that some kind of re-assessment must be conducted at least every 7 years. The rule allows use of confirmatory direct assessment as an interim reassessment for those segments reassessed usin ; one of the other methods at intervals greater than seven years. Reassessments using those methods would be required at 10-year intervals, 15 years for pipe operating at less than 50 pel cent SMYS. Operators of pipe requiring full reassessment every 15 years (Le., affected pipeline segments 39#

Page 41operating at less than 50 percent SMYS) would be expected to perform an interim assessment using confirmatory direct assessment seven years after their baseline assessment. These openltors would then have the option to conduct another confirmatory direct assessment fourteen years ifter their baseline and full assessment in the following year, or they could perform their full assessment in the fourteenth year. OPS assumes that the costs associated with repeating assessments within one year, even if the first were of the limited scope applicable to confirmai:ory direct assessment, will lead most operators in these circumstances to elect to perform their ful I assessments every 14 years. Piping for which full reassessments would be required every 15 ::ears is thus assumed to be subjected to reassessment every 14 years with an interim confirmatory c irect assessment mid-way through the assessment interval. The decision is less straight-forward for operators of pipe required to be assessed at ten year intervals. These operators could perform confirmatory direct assessment seven years followir !g a baseline (or full reassessment) and a reassessment using pressure testing or in-line inspection ;at ten years. (Operators using direct assessment as their assessment technique are assumed to perform reassessments every five years and thus would not face the question of whether to USI : confirmatory direct assessment). Seven years could then expire before another confirmatory direct assessment must be conducted, followed in three years by a full assessment. This cycle would repeat. These operators could, instead, perform full assessments at seven year intervals and thus avoil1 the need to apply confirmatory direct assessment. The decision as to whether to shorten their full reassessment interval or to use confirmatory direct assessment for interim assessments will be made by each operator in consideration of the costs and benefits associated with each choice. Holding to the longer reassessment intervals allowed by the rule would involve administrativt costs to maintain two different assessment programs (the regular assessment method and confirmatory direct assessment). Field work would also be required twice within three years m affected segments of piping. At the same time, confirmatory direct assessment requires testin ; of no additional piping beyond that which can affect high consequence areas and has a lower per - mile cost than hydrostatic testing (and slightly lower than in-line inspection). Decisions by individual operators will depend upon factors specific to their piping systems including the to a1 amount of piping that requires assessment and the amount of additional piping that requires assessment when pressure testing or in-line inspection are used. For purposes of this analysis the OPS assumes that half of the pipe segments that would be required to be assessed at ten year intervals, and thus to conduct interim assessments using confirmatory direct assessment, will instead be assessed at seven year intervals. The other half are assumed to test at ten year intervals and to use confirmatory direct assessment for interim assessments. The number of miles to be tested each year using each assessment method will change as diffi3rent portions of the affected piping enter reassessment. For the first five years, all assessments will be baseline assessments. In year six, reassessments will begin for pipe assessed using direct assessment. In year eight, baseline assessments will be completed for pipe assessed using dirt :ct assessment, and reassessments will begin for that portion of affected piping to be assessed by pigging or hydrostatic testing that it is assumed will be tested on seven-year intervals. In the 40#

Page 42eleventh year, all baseline assessments will be completed and reassessments will begin for th; t pipe to be reassessed on ten-year intervals. Additional piping will begin reassessment in year fifteen, at which time piping operating at less than 50 percent SMYS will begin reassessment. In each year, the amount of piping assumed to be pigged as a result of this rule has been reduced by the assumption that pigging of 1.5 percent of affected piping would have occurred even without this rule. Confirmatory direct assessments will also begin for some piping in year seven. These assessments will be conducted for pipe that is to be reassessed using one of the other methods at ten- or fourteen-year intervals. The confirmatory direct assessments will stop in year fifteen f ,ir pipe that is to be reassessed on fourteen-year intervals, since this analysis assumes that operat )rs will alternate confirmatory direct assessments and full reassessments on this pipe every seven years. The total amount of additional pipeline mileage that will be assessed using each method in thc.: years following the effective date of this proposed rule is displayed in Exhibit 5. Exhibit 5. Additional Pipeline Mileage to be Assessed by Method and Year - Limited Modification Scenario (includes additional pipe that must be tested for pigging and hydrostatic testing, pigging mileage is reduced by amount assumed to be pigged absent rule) Year after Year after Effective Date Effective Date 1-5 1-5 6 - 7 6 - 7 8 - 10 8 - 10 11 - 14 11 - 14 15 - 20 15 - 20 Pigging Hydrostatic Direct Confirmata ry Pigging Hydrostatic Direct Confirmata ry Testing Assessment DA Testing Assessment DA Base Re Base Re Base Re 10-yr 15yr Base Re Base Re Base Re 10-yr 15yr pipe pipe pipe pipe 3,317 0 46 1 0 2,369 0 0 ( 1 3,317 0 46 1 0 2,369 0 0 ( 1 3,317 0 46 1 0 2,369 3,317 0 ( 1 3,317 0 46 1 0 2,369 3,317 0 ( 1 3,317 1,927 46 1 178 0 3,317 785 1 ,3 26 3,317 1,927 46 1 178 0 3,317 785 1 ,3 26 0 1,617 0 303 0 3,317 785 1,3 26 0 1,617 0 303 0 3,317 785 1,3 26 0 3,244 0 545 0 3,317 785 ( 1 0 3,244 0 545 0 3,317 785 ( 1 Cost of Baseline Testing - Limited Modification Scenario Baseline testing costs are estimated by applying the per-mile cost estimates described above tc I the mileage to be tested each year. This includes the cost to modify the 2,764 miles that are assumed 41#

Page 43to be modified to accommodate pigs, at a cost of $9,716 per mile (see Exhibit 4). Cost of Subseauent Testing - Limited Modification Scenario The cost of subsequent testing will be reduced, since the permanent pig launchers and receivei-s and other modifications installed for baseline testing will be used and no additional pipeline modifications will be required. Costs to perform testing may increase slightly due to growth (If populated areas near the pipeline. (Costs may not grow as much as populated areas grow, sin :e additional piping that may meet the definition as affecting high consequence areas may have been included in the additional miles pigged or hydrotested during the baseline period and would therefore not add to the total miles to be tested). The OPS has not considered this growth in t lis analysis. Total Cost of Testing - Limited Modification Scenario The total cost of testing under the limited modification scenario is thus as shown in Exhibit 6 Exhibit 6. Total Cost of Testing Limited Modification Scenario (Annual Costs, in Millions, 2001 dollars) Pipe Modification Scenario The assumption that 65 percent of affected mileage will be pigged under the pipe modificatioi I scenario leaves 35 percent to be assessed using other alternatives. As noted earlier, hydrostatic testing is the least favored alternative. The OPS presumes that much of the pipe that operator j are planning to modify, at considerable cost, to accommodate pigs would otherwise be subject to hydrostatic testing, and that avoiding that testing is a principal reason the industry expects to 42#

Page 44undertake these modifications. Industry preference would therefore clearly seem to be to use direct assessment for the bulk of the remaining piping. The proposed rule would allow direct assessment as the primary assessment method only in c ises where pigging or hydrostatic testing is not economically feasible or would result in substantia I impact on customers (e.g., sole source delivery laterals), or where stress in the pipeline is less than 30 percent of SMYS. Accordingly, OPS assumes that some portion of this remaining pipelin(; will need to be assessed using hydrostatic testing. For purposes of this analysis, the OPS assL mes that the pipe not pigged will be assessed using direct assessment and hydrostatic testing in an 80/20 split. This means that 28 percent of all affected piping (80 percent of the 35 percent noi. pigged) will be assessed using direct assessment and only 7 percent will be hydrostatically tes ted. The OPS invites comment on the percentage of affected pipeline for which operators would usse each acceptable assessment method. Mileage Tested Per Year - Pipe Modification Scenario The amount of piping that will be tested each year changes for the same reasons described for the limited modification scenario above. The mileage tested each year under this scenario is displayed in Exhibit 7. Exhibit 7. Additional Pipeline Mileage to be Assessed by Method and Year - Pipe Modification Scenario (includes additional pipe that must be tested for pigging and hydrostatic testing, pigging mileage is reduced by amount assumed to be pigged absent rule) Year after Pigging Hydrostatic Direct Confirmata ry Effective Date Testing Assessment DA Base Re Base Re Base Re IO-yr 1 5 y r pipe pipe 1-5 5,528 0 322 0 1,474 0 0 6 - 7 5,528 0 322 0 1,474 2,064 0 8 - 10 5,528 2,783 322 125 0 2,064 1,028 1,736 11 - 14 0 3,072 0 212 0 2,064 1,028 1,736 15 - 20 0 5,423 0 318 0 2,064 1,028 Cost of Baseline Testing. - Pipe Modification Scenario 43#

Page 45Performing baseline testing on that portion of natural gas transmission piping that it is assumvd will be pigged will require installation of permanent launchers and receivers and modificatior of some valves on the pipeline mileage it is assumed can easily be modified. It will also include the installation of launchers and receivers, replacement of valves, and replacement of some pipe (e.g., short-radius bends) on piping that must be modified to accommodate pigs but which is assum1:d will be modified for purposes of complying with this proposed rule (referred to earlier as “hadto- pig” pipe). The remaining costs of baseline testing are determined by applyng the per-mile c ists for each method (described above) to the mileage that must be tested (plus 200 percent for pigging and 25 percent for hydrostatic testing). Cost of Subsequent Testing - Pipe Modification Scenario The cost of subsequent testing will be reduced since the permanent pig launchers and receive1 s and other modifications installed for baseline testing will be used and no additional pipeline modifications will be required. Costs to perform testing may increase slightly due to growth (If populated areas near the pipeline (but, as described above for the limited modification scenariq may not increase as much as the high consequence areas grow). The OPS again has not considered this growth in this scenario. Cost to Modify Piping - Pipe Modification Scenario As described above, this analysis assumes 20 percent of existing natural gas transmission piping is piggable, 25 percent can be made piggable with relatively inexpensive modifications, 5 percei it is not piggable, and the remaining 50 percent can be made piggable only with extensive modifications. These percentages are assumed to exist among piping expected to be tested ur der this scenario for compliance with the proposed rule. This scenario concludes that a total of 85,410 miles will be tested. Exhibit 8 shows the mileage in each category, based on applyng the assumed percentages to the total miles to be tested. Exhibit 8. Piggable Mileage within Pipeline to be Assessed - Pipe Modification Scenario I Category I Miles I I Piggable I 17,082 I I Easytomodify I 21,352 I I Hard to modify 1 42,705 I I Not piggable I 3,416 I Total 85,410 A total of 71,865 miles of transmission piping will be pigged under this scenario to comply with 44#

Page 46this proposed rule. This will include all of the piping, within the mileage to be assessed, that is piggable or that can easily be made piggable. The total of these two categories is 38,434 miles. The remaining mileage to be pigged, 33,43 1 miles, must come from modification of pipeline hat is relatively harder to modify. The costs to modify piping are thus as presented in Exhibit 9. Exhibit 9. Costs to Modify Piping to Accommodate In-line Inspection - Pipe Modification Scenario Category Miles $/mile (millions) I Piggable 17,082 1 Easytomodify I 21,352 I 9,716 I 207.5 I Hard to modify I 33,431 I 40,000 I 1,337.2 I I I -1 I Total I 71,865 I NA I 1,544.7 The modifications will be made throughout the period in which baseline assessment by piggir g occurs, or ten years. The modification cost per year will thus be $154.5 million. Total Cost of Testing - Pipe Modification Scenario The total cost of testing is thus as shown in Exhibit 10. Exhibit 10. Total Cost of Testing Pipe Modification Scenario (Annual Costs, in Millions, 2001 dollars) Year after Pigging Effective Date Hydrostatic Direct Confirmatory Testing Assessment DA Base I Re 1 Base 1 Re I lo; 1 1 5 y r pi le 1-5 I 172.2 I 0 6 - 7 I 172.2 I 0 1.7 1 0 I 7.08 I 0 I 0 I It- 8 - 10 I 172.2 I 8.9 0.66 9.9 3.08 5.::!1 11 - 1 4 I 0 I 9.86 - 1.12 9.9 3.08 5.:!1 1 5 - 2 0 I 0 I 17.41 ~ 0 1.68 0 9.9 3.08 ( 1 45#

Page 47Costs of Service Interruption The Interstate Natural Gas Association of America (INGAA) sponsored an analysis27 evaluati ig the costs to consumers from service interruptions that they presumed would occur if testing requirements such as those included in the proposed rule were imposed. This analysis is avai able in the docket. It concluded that consumer costs would rise, perhaps significantly, due to increased costs of gas transmission if portions of the transmission pipeline network were required to be removed from service for testing. Both the Department of Energy (DOE) and the Office of Pipeline Safety have analyzed the INGAA report. The OPS contracted with the Volpe National Transportation Systems Center io review INGAA's report. Both evaluations were performed considering the estimates in the preliminary draft regulatory evaluation prepared for discussion with TPSSC. Both DOE and 1 he Volpe Center concluded that the proposed rule would not have an impact on the domestic pric,e of natural gas. The OPS notes that the conclusions of DOE and the Volpe Center were both predicated, in part, on the ability of operators to conduct inspections during non-peak demand periods, and under the assumptions used in the preliminary draft analysis most testing should liave been able to be performed during off-peak times. This is no longer the case. Revisions made following discussion at the TPSSC meeting, as described in various places above, result in assuming that a much larger portion of the total national gas transmission pipeline network will be tested. This greatly curtails, probably eliminating, the ability of operators to perform all testing during off-peak periods. As a result, the OPS acknowledges that there wil be some cost increase to consumers as a result of curtailment of the ability to transport gas durin; ; testing. The OPS does not know how large this cost will be and has not included it in the cos1 estimates in this analysis. The OPS notes that the ability to test at non-peak periods would be restricted further if assessments were required to be performed on very short intervals. Thus, greater cost impact would be likely to occur if testing were required at five year, or perhaps seven year intervals. Consideration of Remote Control Valves (RCV) and Automatic Shutoff Valves (ASV) The proposed rule requires operators to conduct a risk analysis of their pipeline to identify additional actions to enhance public safety. Such actions include, but are not limited to, instal ling ASVs or RCVs, computerized monitoring and leak detection systems, extensive inspection and maintenance programs, etc. If an operator determines that an ASV or RCV is needed to prote.:t high consequence areas in the event of a gas release, the operator must install the valve. Natural gas transmission lines are already required to be equipped with sectionalizing block 27"Consumer Effects of the Anticipated Integrity Rule for High Consequence Areas," prepared for the INGAA Foundation, Inc. by Energy and Environmental Analysis, Inc., 2002 46#

Page 48valves.2* The required spacing of these valves varies for different class locations. Valves mu ;t be no more than 5 miles apart in class 4 areas, 8 miles apart in class 3, 15 miles apart in class 2 a id 20 miles apart in class 1. Some of these valves are presently remotely operable. The requirer lent of the proposed rule will have the primary effect of requiring operators to conduct risk assessments to determine if conversion of any of the now-manual valves to remote or automa ic operation is needed. The OPS completed a feasibility study on remotely controlled valves on interstate natural gas pipelines in 1 999.29 In conjunction with that study, the OPS conducted a public meeting and solicited written comments (see 62 Federal Register 5 1624, October 2, 1997). The study determined that conversion of valves to remote operation was not economically feasible. Mo:d fatalities and injuries resulting from natural gas pipeline ruptures occur very quickly, before the time that would be required to isolate the pipeline using RCVs. Similarly, a significant amou it of the property damage experienced in historical accidents occurred immediately after the ruptur ,;. The 1999 feasibility study determined that the value of gas lost before the pipeline could be isolated would be the principal benefit, and that the value of that benefit did not offset the c0st.s of converting the valves. Operators will need to re-visit this generic conclusion for particular pipeline segments that cai 1 affect high consequence areas. The OPS expects that the conclusion that most fatalities and injuries could not be avoided by conversion of valves will not be changed, since historical accident experience shows that injuries and fatalities occur very quickly after any pipeline nq ture. Circumstances specific to individual pipeline segments that can affect high consequence area: could, however, change the generic conclusion that significant property damage cannot be avoided through use of RCVs. This could lead to a need to convert some sectional valves to remote operation. The 1999 study reported on the results of a one-year field evaluation of RCVs conducted by T exas Eastem Transmission Corporation (TETCO) pursuant to a settlement agreement in the complj ance case involving the 1994 pipeline rupture in Edison Township, NJ. The study reported that TETCO experience indicated that costs to install a RCV ranged from $150,000 to $500,000, depending on the number of valves at the same locations and variations in permitting costs. 7 he study further estimated that the cost for converting an existing valve, on average, was betweeri $125,000 and $150,000, including efficiencies that could be realized by dividing site costs ov :r a number of valves in an individual location. The study concluded that there was no significanl: impact on direct operating costs, since the maintenance activities for the additional equipmen1 were absorbed in the function of the personnel working valve sites for other purposes. The OPS does not have any information on which to base a conclusion about how many natural gas transmission line sectional valves may be converted to RCVs. Because there are so many 2849 CFR 192.179, “Transmission Line Valves” 29“Remotely Controlled Valves on Interstate Natural Gas Pipelines (Feasibility Determination Mandate 1 by the Accountable Pipeline Safety and Partnership Act of 1996)”, September 1999. 47#

Page 49factors in an operator’s decision to install or not to install these valves, OPS has decided there would be no valid approach, including a sensitivity analysis to make such an estimate. The 0 PS has thus not estimated the industry costs to convert valves. The OPS assumes that operators will not make such conversions unless the benefits (expected reduced property damage and value I )f lost gas) exceed the approximately $150,000 conversion cost, and thus there should be no net cost from valve conversions. Operators will be required to analyze their systems to determine whether it is cost-beneficial ti3 convert valves. The OPS assumes that these analyses will be conducted by staff engineers. T he time required for these analyses is expected to be relatively small, since generic conclusions at-e already available and the effect of site-specific factors will be the focus of operator evaluations. The OPS estimates that this will require approximately several man-months for pipeline operiltors with more than 40 miles of pipeline, at a cost of approximately $50,000.30 Operators with les .; than 40 miles of pipeline should be able to conduct these evaluations in about half the time at a cost of approximately $25,000. The total cost for considering the need to convert valves to ASV or RCV is thus $24.1 millior . These costs will be incurred once and are assumed to be incurred in the first year after the proposed rule becomes effective. The Costs of Data Integration As 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 thi .; integration will require that operators’ internal data management systems be aligned and maniiged 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 of natural and other gas transmission pipelines are expected to develop integrity management plans in response to this rule and will need to implement new actions to assure d,ata integration. These actions will need to include realignment of data management systems that ‘will occur in the first year (concurrent with development of the integrity management plan) and continuing costs for assessment of the integrated data. As before, the OPS assumes that 25 percent of the natural gas transmission pipeline operators with more than 40 miles of pipeline have already developed comprehensive integrity management plans and will incur no additior a1 costs as a result of this proposed rule. The OPS also assumes that development of data integr< ition processes will be easier for operators that only operate a few miles of pipeline. The OPS estimates that first year costs for the impacted operators with 40 or more miles of 30The previously estimated cost of a senior engineer/supervisor man-year of $120,000 has been considei.ed 48#

Page 50pipeline will be $100,000 and that continuing costs will be $50,000 annually thereafter)'. For operators with less than 40 miles of pipeline, the OPS estimates that first year costs will be $25,000, and that continuing costs will be $12,5003'. Total costs for data integration for the 222 operators with more than 40 miles of pipeline that :are expected to develop plans will be $22.2 million in the first year and $1 1.1 million annually in following years. Data integration costs for the 372 operators with less than 40 miles of pipeli le will be $9.3 million in the first year and $4.65 million annually thereafter. The Cost of Remedial Action Inspection and testing and integration of other relevant data will identify anomalies that must Ibe investigated and remediated. The number of anomalies that will require action or the cost of 1 hat action can not be known until the assessments are performed. In addition, other provisions of Part 192 require operators to repair known anomalies that can impact pipeline integrity; the requirements of the proposed rule merely serve to identify the anomalies. Costs associated w' th remediation are therefore not estimated as part of this analysis. TOTAL COSTS Costs have been estimated for: (1) identifying pipeline segments that can affect HCAs, (2) plans and reports, (3) evaluating valves for possible conversion to automatic closing or remote operation, (4)testing, and ( 5 ) data integration. Testing costs, have been estimated for two diff .:rent scenarios. Exhibits 1 land 12 present a summary of these costs, for each testing scenario analyzed, presented by the year that they are incurred after the effective date of the final rule. 3'These values are twice those assumed for the corresponding fhctions in the regulatory analyses for bl Ith rules affecting hazardous liquid pipeline operators, reflecting comments that costs were underestimated in those analyses. 320PS did not estimate lower costs for any operators affected by the companion rules for hazardous liqi id pipelines. Few hazardous liquid pipeline operators operate only a few miles of pipeline. In this instance, 372 operators operate less than 40 miles of natural gas transmission pipeline. OPS considers that the realignment of management systems for information related to so few miles of pipeline will be considerably simpler, and has estimated here that it will cost these operators one-fifth as much effort. 49#

Page 51EXHIBIT 11. THE ESTIMATED COST OF THE PROPOSED REGULATORY CHANGE - Limited Modification Scenario (Costs in millions of 2001 dollars) Year Segment Integrity after ID Annual Valve Baseline Subsequent Integrate Total Plans Reports Analysis Testing Testing Data Cost effective date of final rule 1 $23.34 $91.27 $13.36 $24.1 $51.3 $31.5 9234.9 2 $0 50 $13.36 $0 $51.3 $0 $15.75 $80.41 3 $0 $13.36 $0 $51.3 SO $15.75 $80.41 4 $0 $13.36 $O $51.3 SO $15.75 $80.41 5 $0 SO $13.36 $O $51.3 $15.75 $80.41 6 $0 SO $13.36 $0 $51.3 $15.92 $15.75 $96.34 $0 SO $13.36 $0 $51.3 $15.92 $15.75 $96.34 8 $0 SO $13.36 $O $39.93 $29.38 $15.75 $98.42 9 SO SO $13.36 SO $39.93 $29.38 $15.75 $98.42 10 SO SO $13.36 SO $39.93 $29.38 $15.75 $98.42 SO SO $13.36 SO $29.04 $15.75 $58.15 SO $13.36 $29.04 $15.75 $58.15 13 $0 $0 $13.36 SO $0 $29.04 $15.75 $58.15 14 $13.36 $29.04 $15.75 558.15 15-20 $0 $0 $13.36 $0 $0 $31.08 $15.75 $60.19 50#

Page 52EXHIBIT 12. THE ESTIMATED COST OF THE PROPOSED REGULATORY CHANGE - Pipe Modification Scenario (Costs in millions of 2001 dollars) Year Segment Integrity Annual Valve Baseline Subsequent Integrate Total after ID Plans Reports Analysis Testing Testing Data Cost effective date of final rule 1 $23.34 $91.27 $13.36 $24.1 $181 $31.5 $:64.6 2 $13.36 $181 $0 $15.75 $::10.1 3 $0 $13.36 $181 SO $15.75 $210.1 4 SO $0 $13.36 $181 SO $15.75 $:210.1 5 SO SO $13.36 SO $181 $0 $15.75 $210.17 6 $0 $13.36 $181 $9.9 $15.75 $220 7 SO $0 $13.36 SO $181 $9.9 $15.75 5220 8 SO $0 $13.36 SO $173.9 $27.79 $15.75 $230.8 9 $0 SO $13.36 $0 $173.9 $27.79 $15.75 $230.8 10 $0 $13.36 SO $173.9 $27.79 $15.75 $230.8 $O $13.36 SO $29.18 $15.75 $58.29 -- 12 $0 $13.36 $0 $29.18 $15.75 $58.29 13 $0 SO $13.36 SO $0 $29.18 $15.75 $58.29 14 SO $0 $13.36 SO $29.18 $15.75 $58.29 CONCLUSIONS Issuance of this proposed rule as a national standard will ensure that all operators will perforn: at least to a baseline safety level and will contribute to an overall higher level of safety nationwi de. It 51#

Page 53will lead to greater uniformity in how risk is evaluated and addressed and will provide more cl, lrity in discussion by government, industry and the public about safety issues 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’ development of more formal, structured risk evaluation programs and in OPS’s evaluation oft iem. It provides greater ability for operators to customize their long term maintenance programs. It 1 ias also stimulated the development of a supplemental industry standard, which is referenced in the proposed rule. A performance-based approach will also encourage the development and matui ing of risk-based approaches to integrity management. Our emphasis on the integrity management system encourages a balanced program, addressing 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 most significant risLs, and is the best opportunity to improve industry performance and assure that the high conseque ice areas get the protection they need. It also addresses the interrelationships among failure causes and benefits. It promotes the coordination of risk control actions, beyond what a compliance-basec I approach would achieve. The proposed rule provides for a verification process, which gives the regulator a better oppor unity 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 to the adequacy of the operators’ decision process. This leads to greater accountability to the public. A particularly significant benefit is the quality of information that will be gathered as a result ,f this rule to aid operators’ decisions about providing additional protections. Two essential element,; of the integnty management program are that an operator continually assess and evaluate the pip1 :line’s integrity and perform an analysis that integrates all available information about the pipeline’s integrity. The process of planning, assessment and evaluation will provide operators with beti er data on which to judge a pipeline’s condition and the location of potential problems that must be addressed. Integrating this data with the safety concems associated with high consequence areas will helr prompt operators and the Federal and state governments to focus time and resources on poteni ial risks and consequences that require greater scrutiny and the need for more intensive preventiv,: and mitigation measures. If baseline and periodic assessment data is not evaluated in the proper C I mtext, it is of little or no value. It is imperative that the information an operator gathers is assessed i.1 a systematic way as part of the operator’s ongoing examination of all threats to the pipeline integity. The proposed rule is intended to accomplish that. The cost estimates in this evaluation reflect the estimated costs for operators to establish the necessary integrity plans and data integration processes, to integrate and analyze the data, to consider the need to convert some valves, and to perform testing of piping in high consequence 52#

Page 54areas. The evaluation reflects the fact that some operators have begun testing programs and wwld be expected to continue those programs without this proposed rule. The cost for operators to identify pipeline segments that can affect high consequence areas is estimated to be $23.34 million. These costs will be incurred in the first year after the effective date of the rule. The integrated cost to all operators for developing integrity management plans is estimated to be $90.9 million (plus $370,000 for providing real-time access to performance measures). Annua 1 costs of $13.36 million are projected to review the plans, make changes as needed, and to prep ire routine reports. First year costs for performing the necessary data integration are estimated to )e $3 1.5 million, reflecting the need for operators to adjust their management systems to assure that the relevant data can be collected and analyzed. Those process changes will not be required in following years, when the costs for data integration are estimated to be $15.75 million annual1 I . Testing is a key element of the rule. It is also the element that can vary most significantly in CI )st. This evaluation considers two possible scenarios. One assumes that a considerable amount of piping will be modified by the addition of permanent launchers and receivers for in-line inspec tion equipment, replacement of valves, and elimination of short-radius bends. The other assumes t iat a smaller amount of piping will be modified, and that the modifications will be less extensive. I {oth increase the costs of in-line inspection for baseline inspections, which would occur under the proposed rule for the first ten years. A portion of transmission piping in high consequence areas will be inspected each year, using one of three specified methods. (The proposed rule would allow operators to use alternative methc Ids, with adequate justification, but no additional methods are projected in this analysis). The tota cost across the industry for testing, including the necessary modification of some pipelines, is estin ,ated to be between $5 1.3 and $18 1 million annually (the total in each of the analyzed scenarios) foi each of the first five years after the proposed rule becomes effective. Testing costs are expected to increase in the sixth and seventh years, because operators will be required to re-assess piping assessed in the first two years by direct assessment while they are still completing baseline inspections. Testing costs in years six and seven will be between $67.2 and $191 million. Te ;ting costs will be between $69 and $202 million annually for the next three years, in which baselin:: assessments by direct assessment will have been completed and focused assessments must be conducted on some pipe to be assessed at longer intervals. Testing costs will be between $29 ,md $32 million annually thereafter, under either scenario, when all costs to modify pipelines for pigging will have been incurred. As described in the evaluation, it is difficult to quantify the benefit of this proposed rule, beca.ise it is not now possible to estimate with certainty the effectiveness the proposed requirements woi ild have in avoiding natural gas transmission pipeline accidents. Sixteen years of data indicate that the benefit of the rule in avoiding deaths, serious injuries, and property damage would be equal tc $53.25 million annually if these measures are completely successful in avoiding accidents liktr those reflected in the current data. Even though this represents the monetized value of all deaths, SE rious 53#

Page 55injuries, and property damages reported in the last 16 years, it is not necessarily a bounding estimate. Future accidents are likely to have greater consequences, as described in the analysis. In addition, avoiding major accidents, with multiple fatalities, can result in greater benefit. The 16 years of data considered include two years (eleven years apart) in which accidents occurred th: t had many fatalities. The most recent of these accidents was the explosion and fire caused by a pip1 :line rupture near Carlsbad, NM on August 19,2000, which caused 12 fatalities. The frequency of uch major accidents could be greater in future years absent some regulatory change. This evaluation demonstrates that the costs for implementing the proposed rule will be larger t'ian the monetized benefits it will provide. As described, the maximum quantitative benefit that the rule could provide, assuming future accident rates and consequences consistent with the recent historical record and that the proposed rule is completely effective in eliminating such accidents, is $53. !5 million. The proposed rule is directed at that portion of natural gas transmission pipelines wt ere an accident is most likely to result in the highest consequences, the pipeline mileage in the areas 'vith highest population density. The OPS therefore believes that the rule will be quite effective in avoiding deaths, serious injuries, and property damage from gas pipeline accidents, and that the benefit thus realized will be on the order of $40 million. As a result, the benefits are of the sal ne order of magnitude as the annual costs for assessment of approximately $30 million. They arc slightly less than the total annual estimated costs (aAer pipeline modifications are completed) if $60 million. The up-front costs that will be incurred as a result of the proposed rule are substantial, however, and are not justified by the resulting quantifiable benefits. Incurring them is necessary in order to establish the improved framework for operator management and regulator oversight of safety. As described in the analysis, there are a number of qualitative benefits that will be realized from the proposed change. Foremost among these is providing a basis for improved public confidence in pipeline safety. Economic benefits are expected to accrue from this increased level of confidence, including reduced costs for siting and constructing new pipeline, thereby allowing access to tb e environmental benefits of increased use of natural gas in lieu of other fuels. Comments by mc mbers of the Technical Pipeline Safety Standards Committee (TPSSC), and members of the interested public who spoke at their July 18, 2002, meeting, indicate their belief that the benefit of increased public confidence to be realized by implementing the proposed rule justifies its costs. The estimated costs are certainly large, but need to be considered in context. Many of these C I )sts will be reflected as increases in the cost of natural gas. During 2000, a total of 20.772 trillion cubic feet of natural gas was delivered to U.S. consumers.33 If the total projected first-year costs of between $235 and $364 million are divided over this quantity of natural gas, the result would be an increase in delivered price of between 1.1 and 1.75 cents per thousand cubic feet. The averag ,: U.S. residential customer used 84 thousand cubic feet of natural gas in 2000.34 The effect of these ,:osts would therefore be an increase in the monthly bill for this average residential consumer of between 33Natural Gas Annual, Energy Information Adrmnistration, page 38. 341bid, page 37. Determined by dividing the reported total volume of natural gas delivered to consumeI*j by the reported number of consumers. 54#

Page 568 and 12.5 cents. After the first ten years, when all pipeline modifications are completed, the increase in average residential cost would be 2 cents per month. The OPS believes that the process of developing an integrity framework and schedule and integrating data related to pipeline integnty is an important process for the operator, the goven iment 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 the testing schedule, also provides a level of confidence to Federal and state pipelint inspectors that pipeline operators are considering, examining, testing, and repairing if necessa1 y, natural and other gas transmission pipelines that potentially pose severe consequences to public safety. Finally, standardizing the requirements nationally for transmission pipelines will save operators having to face potentially different testing and inspection requirements from the various state pipeline agencies. The OPS concludes that the qualitative benefits justify the costs associated with initial implementation of the proposed requirements. Appendix - Sensitivity Analyses The OPS considered several different ways in which the requirements of this rule could be chaged that would have an effect on estimated costs. These changes all involved modifications to the interval at which periodic testing would be required. The effect on costs of these alternatives s presented in this appendix in the form of sensitivity analyses. Two separate analyses are pres€ nted. First, requiring inspection at shorter intervals, for both baseline assessment and subsequent reassessment. Second, modifying the reassessment interval for pipe assessed using the direct assessment technique to 10 years. I. Alternate Testing Intervals The OPS considered alternate requirements that would have required baseline and subsequent reassessments to be conducted more frequently (Le., at shorter intervals). For purposes of analysis, intervals of five and seven years were considered. For these sensitivity cases, all baseline assessments and all re-assessments were considered to occur on the same interval. (The propcised requirements include a shorter interval for assessments performed using direct assessment, as described above. The OPS concluded that requiring a shorter interval for direct assessment w iuld not be practical if the interval for other testing methods was this short). No focused assessme Its (Le., confirmatory direct assessment) are performed in this case, since full assessments are performed for all affected pipe on intervals not longer than seven years. The per-mile costs for each assessment method remain unchanged in the sensitivity analysis. The sensitivity analysis considers both testing scenarios, and the percentages of gas transmission pipeline mileage assumed tested using each method also remain the same in each. This mean I; that under the limited modification scenario 27,64 1 miles of pipeline would require modification a d 55#

Page 57under the pipe modification scenario 54,784 miles of pipeline would still be required to be mo lified to facilitate pigging. The modifications would be made, as before, to facilitate baseline assessments, but the annual costs would be higher since the baseline assessments must be completed over fewer years. Also as before, the permanent modifications would be available or future reassessments by pigging, and the cost of reassessments would thus decrease. There would be no difference in annual costs between baseline and reassessment under the anAyzed alternate scenarios. Testing costs under these alternative scenarios are shown in Exhibit 13. Exhibit 13. Total Cost of Testing Under Alternate Intervals (Annual Costs, in Millions, 2001 Dollars) I Test Method I 5 ~ e a r s I 7 ~ e a r s I 1 Direct Assessment 1 15.92 -9.91 I 11.37- 7.08 I I Hydrostatic Testing I 4.86- 3.40 I 3.47- 2.43 I In-Line Inspection 21.30 - 35.49 15.21 - 25.35 Modify Pipelines 53.71 - 309.0 38.37 - 220.7 (Baseline Tests Only) 1 Total - Baseline I 95.79 - 357.74 I 68.42 -255.53 I Total - Reassessment 42.08 - 48.80 30.06 - 34.86 Total costs rise under the shorter assessment intervals, as expected. The amount of increase is less under the 7-year scenario, although annual costs for baseline assessments are from $17.12 to !,74.53 million higher and costs for reassessments are approximately the same to slightly lower for thc limited modification scenario. These numbers actually understate the difference. As described above, the proposed requirements would allow for longer test intervals for medu im consequence areas. These longer intervals have been ignored for simplicity in the cost analys s displayed in Exhibits 6 and 10. The result is conservative in evaluating the impact of the proposed rule, in that costs are overestimated. The assumption results in non-conservative conclusions when these costs are compared to the estimated costs for alternate intervals that would apply to all F iping, even those able to affect relatively smaller populations. The difference in costs between the alternatives is actually higher than indicated in the comparison between Exhibits 6 and 10 anc 56#

Page 58Exhibit 13. The OPS concluded that the additional costs for shorter inspection intervals were not justified. The shorter intervals would not result in any additional pipeline being assessed. They would simp1 y require assessments of the same pipeline segments more frequently. The degradation mechaniljms that the inspections are designed to detect (internal corrosion, external corrosion, stress corrosj on cracking and external damage to the pipeline) are generally not fast-acting. Damage progresses slowly, and only after many years would be expected to result in pipeline failures. The focusel i reassessments required by the proposed rule for pipe with longer reassessment intervals are int Iended to identify unexpected instances of more rapid defect growth. In rare instances in which partic ular risk factors introduce the likelihood of damage occurring more rapidly, the proposed rule wou d require the operator to re-assess at shorter intervals. Thus, the additional costs of inspecting a 1 piping at more frequent intervals cannot be justified by an assumption that more frequent testii ig would prevent more pipeline accidents. Shorter inspection intervals would also exacerbate any impact fi-om supply interruption. As described in the main analysis, the OPS now accepts that some supply interruption is likely to occur for the inspection intervals specified in the proposed rule. The amount of this disruption is unknown, and related costs have not been reflected in this analysis. Requiring testing at short1 :r intervals would certainly increase the amount of supply interruption and related costs. This reinforces the conclusion that requirements for more frequent testing are inappropriate. Finally, requiring more frequent testing would exacerbate near-term supply problems among pipeline testing contractors. The increased demand would likely result in proliferation of vendors who would lack expertise and experience. Testing might be performed more quickly, but the ,esults would not be as reliable. For all of these reasons, the OPS rejected shorter inspection intervals in favor of the intervals reflected in the proposed rule. 11. Modified Assessment Intervals for Direct Assessment As described in the analysis, direct assessment is a new technique for evaluating pipeline intelyrity. Development of industry standards governing this technique has only recently been completec . There is very limited experience with use of this technique in the field. The proposed rule requires that baseline assessments be completed more rapidly if direct assessment is used (7 years vs. 10) and that reassessments be completed even more rapidly (5 years vs. 10 or 15). (As described n the analysis, the intervals are extended for pipe that can affect medium consequence areas assessed using direct assessment. The effect of that difference has not been considered in the main ana lysis and is again not considered in this sensitivity study). The reason for these shorter intervals is uncertainty regarding the effectiveness of direct asses .;merit. This technique, as described further in the main analysis, uses indirect measurement tools to i8 ientify locations of potential degradation. At least some of those locations are then excavated and 57#

Page 59examined directly to identify indications requiring repair. The use of these indirect measureml :nt tools for this purpose is new. The OPS expects that direct assessment will be a valuable methc Id for assessing integrity, and will be the only practical method for assessing some pipe (e.g., pipe th it cannot be removed from service without interrupting natural gas supply to customers). At the same time, the lack of experience with this technique causes some uncertainty over its ability to ider tify and correct all important pipeline anomalies, and makes it more likely that some important anomalies could be missed. These uncertainties are the reason that the OPS has concluded that assessments using this technique should be performed more frequently, to increase the likelihc od that any anomalies missed in an original assessment will be detected in a reassessment before hey can result in a pipeline accident. The requirement that assessment intervals be reduced when direct assessment is used has the effect, however, of increasing the cost to conduct assessments for pipe evaluated with this technique. OPS performed this sensitivity study to examine the magnitude of the overall increase in cost that rcsults from this conservatism. As described above for the inspection interval sensitivity study, the per-mile costs of each assessment technique, the amount of pipe to be tested, the amount of that pipe that will requirv modification, and the relative percentages of pipe that will be assessed using each technique are not changed in this study. The only change is the periodicity with which direct assessment must be performed. As a result, and as in the previous sensitivity study, the only effect is a change in testing costs. OPS has assumed, for purposes of this sensitivity study, that direct assessment baseline inspections would still be required to be completed over a period of ten years. Reassessments using direcl assessment are assumed to be required on ten-year intervals rather than the five-year interval specified in the proposed rule. (Under the proposed rule, some reassessments using other techniques would be required on 15-year intervals, where stresses in the pipe are below 50 per cent SMYS. OPS has not assumed that this additional relaxation would be allowed for direct assessment. The industry standards governing direct assessment do not contemplate such relaxation, and OPS is unwilling to extend the reassessment interval to 15 years in light of the currently-unknown effectiveness of this new assessment method). Since this would result in periods longer than seven years between assessments, focused reassessments using confirmatclry direct assessment would be required. As described in the main analysis for other pipe subject to ten-year reassessment intervals, operators in this case would be faced with a decision regardin12 whether to use the full ten-year interval and perform focused interim assessments or whether to perform full reassessments every seven years. Here, unlike in the main analysis, the OPS asst mes that all operators would use the full ten-year interval and perform focused interim assessments. To assume otherwise would reduce the value of this sensitivity study, since it would involve mucli pipe being reassessed at the same intervals considered in the main analysis. Testing costs for direct assessment and related confirmatory direct assessment under these assumptions would be as presented in Exhibit 14. The costs for hydrostatic testing, in-line inspection, modifyng pipelines, and for confirmatory direct assessments related to those met1 ods 58#

Page 60do not change, and are not shown here. Exhibit 12. Cost of Direct Assessment Under Under Alternate Reassessment Intervals (Annual Costs, in Millions, 2001 Dollars) Year after 1 5-year interval I 10-year interval 1 Effective Date DA CDA DA CDAI 6 - 7 27.3 - 17 0 11.4 - 7.1 (baseline + reassess) (baseline only) O I 8 - 10 15.9 - 9.9 0 0 7.1 - 4.4 11 - 14 15.9 - 9.9 0 11.4-7.1 15 - 17 15.9 - 9.9 0 11.4 - 7.1 18 and after 15.9 - 9.9 0 0 7.1 - 4.4 Again,in each case, the first value represents the limited modification scenario and the second value represents the pipe modification scenario. The values appear reversed, because fewer miles are subject to direct assessment in the pipe modification scenario. Costs are zero for direct assessment or confirmatory direct assessment during some periods under the 10-year scenario, because the baseline assessments are assumed to be conducted in 7 years One-seventh of the total amount of pipe to be direct assessed therefore comes due for interim assessment each year beginning in year 8 and for reassessment in year 1 1. The first round of i iterim assessments ends after year 14, while reassessments continue until year 17. The ten-year cych then begins anew, with the same 3-year gaps in each cycle. Eliminating the gaps would require that the baseline period also be extended to 10 years, which the OPS is unwilling to do given the untested nature of this technology. Total costs for reassessments using direct assessment (including interim reassessments) over t le 20- year period considered in this analysis would be reduced fi-om $238 to $129 million under the limited modification scenario and from $149 to $94 million under the pipe modification scenfrio. This equates to a savings of between $3.5 and $7 million per year for the 15 years that reassessments using direct assessment would be conducted under the provisions of the propos .:d rule (5-year reassessment interval), or from 6 to 12 percent. No savings would be realized duiing the first five years, because the baseline assessment period is not changed. These savings are substantial, but they are not so large as to drive the decision. The savings d;, not occur for several years. The technique is still new and relatively untested. During those years, field experience will be gained using direct assessment. This experience may alleviate concerns regarding this new technique, or it may demonstrate those concerns to be valid. The OPS considers 59 .. .#

Page 61that assessment intervals for this technique should be established as described in the proposed rule. The reassessment interval may be revisited as more experience is gained with this technique. 60#