# U.S. DOT/PHMSA - Report to Congress - **operation:** document - **citation:** 0900006480e836bd - **title:** U.S. DOT/PHMSA - Report to Congress - **source type:** rulemaking - **agency:** Pipeline and Hazardous Materials Safety Administration - **status:** current - **official:** true - **published on:** Not available - **effective on:** Not available - **summary:** Assuring the Integrity of Gas Distribution Pipeline Systems A Report to the Congress May 2005 Submitted by: Office of Pipeline Safety Pipeline and Hazardous Materials Safety Administration U.S. Department of Transportation Table of Contents Executive Summary………………………………………………………………………….1 1. Program Overview………………………………………………………………………..2 2. Regulation of Distribution Systems and the Role of State/Federal Governments………..4 3. The Gas Distribution Safety Baseline…………………………………………………….5 Diversity of Operators………………………………………………………………..5... - **machine formats:** - **json:** https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e836bd.json - **markdown:** https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e836bd.md - **app url:** https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e836bd - **source url:** https://downloads.regulations.gov/PHMSA-RSPA-2004-19854-0074/attachment_1.pdf **body:** <<>> Assuring the Integrity of Gas Distribution Pipeline Systems A Report to the Congress May 2005 Submitted by: Office of Pipeline Safety Pipeline and Hazardous Materials Safety Administration U.S. Department of Transportation <<>> Table of Contents Executive Summary………………………………………………………………………….1 1. Program Overview………………………………………………………………………..2 2. Regulation of Distribution Systems and the Role of State/Federal Governments………..4 3. The Gas Distribution Safety Baseline…………………………………………………….5 Diversity of Operators………………………………………………………………..5 Diversity of Infrastructure……………………………………………………………7 Existing Regulations and Practices…………………………………………………..7 Insights from Incident Data…………………………………………………………..9 Innovative Practices…………………………………………………………………11 Monitoring the Effectiveness of Actions……………………………………………11 4. Evaluation of Applicability of Transmission IM Program and Practices………………..12 Integrity Management Elements…………………………………………………….12 Applicability to Distribution Pipeline Systems……………………………………...12 Identifying High Consequence Areas………………………………………..12 a. Hazardous liquid pipelines……………………………….………….12 b. Gas transmission pipelines…………………………………………..13 c. Gas distribution pipelines……………………………………………13 Assessing Pipeline Integrity………………………………………………….14 a. In-line Inspection…………………………………………………….14 b. Pressure testing………………………………………………………14 c. Direct Assessment……………………………………………………15 Applicability of Current IMP Practices………………………………………………17 5. Principles Guiding the PHMSA Approach………………………………………………..17 6. Plan and Schedule for Defining and Implementing Distribution Integrity Management Requirements…………………………………………………………………………………19 7. Options Being Considered………………………………………………..……………….21 Specific Attention to Excess Flow Valves……………………………………………25 8. Conclusion………………………………………………………………………………...26 Attachments 1. NAPSR State Survey Results -- State Requirements beyond Federal Regulations Gas Distribution Systems 2. Summary of Allegro Report – Safety Incidents on Natural Gas Distribution Systems: Understanding the Hazards, April 2005 3. NARUC Resolution on Distribution Integrity Management, February 16, 2005 4. Position of the American Public Gas Association on Distribution Integrity Management 5. PHMSA/OPS Phase 1 Action Plan List of Figures 1. Distribution systems subject to 49 CFR 192………………………………………………..6 2. Relationship among Federal Requirements, Standards or Guidelines, and State Requirements…………………………………………………………………………………23 3. Example of High-level Federal Performance Requirements……………………………...24 i <<>> Acronyms AGA – American Gas Association AGF – American Gas Foundation APGA – American Public Gas Association CFR – Code of Federal Regulations DA – Direct Assessment DOT – Department of Transportation EIA – Energy Information Administration EFV – Excess Flow Valve FR – Federal Register ILI – In-line inspection IM – Integrity Management IMP – Integrity Management Plan LP – Liquid propane NAPSR – National Association of Pipeline Safety Representatives NARUC – National Association of Regulatory Utility Commissioners OPS – Office of Pipeline Safety PHMSA – Pipeline and Hazardous Materials Safety Administration USC – United States Code ii <<>> A Report to the Congress: Assuring the Integrity of Gas 1 Distribution Pipeline Systems Executive Summary The FY 2005 Conference Committee on Appropriations asked1 the Department of Transportation’s (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA) Office of Pipeline Safety (OPS) to submit a report detailing the extent to which integrity management plan elements may be applied to gas distribution pipeline systems to enhance safety. “Integrity management” refers to programs that OPS has required of hazardous liquid and gas transmission pipeline operators, through rules promulgated within the last five years. Integrity management requirements have not yet been established for gas distribution pipeline systems. The Department of Transportation’s (DOT) Inspector General recommended that OPS take this action in testimony before the Congress in 2004.2 The principal focus of the existing integrity management regulations for pipelines is to identify the portions of the pipeline system that pose the most risk; to inspect the physical condition of those portions of the pipelines; and to repair any defects that could challenge the pipeline integrity. The fundamental principles of integrity management require: understanding the infrastructure and the risks it poses, and then taking actions to address those risks. There are significant differences in the design of gas distribution pipeline systems compared to the pipelines subject to current integrity management regulations. These include pipe size, operating pressure, materials, and the large number of branches and connections in distribution systems. These design differences significantly limit the applicability of the inspection techniques currently in use for those pipelines to distribution pipeline systems. The challenge is to develop appropriate methods to apply the principles of integrity management to enhance the safety of distribution pipeline systems, while remaining mindful of costs and service disruptions and their potential impact on consumers. Gas distribution pipelines, those that deliver gas directly to consumers, are almost entirely under the regulatory oversight of state agencies. OPS has implemented a program jointly with its state partners and a broad range of stakeholders, to identify means appropriate to distribution pipelines to focus attention on areas that pose the highest risk and to better assure the integrity of those portions of the distribution systems, in other words, integrity management. The first phase of the program is to be completed in 2005 and will identify the nature of requirements that might be imposed and any additional guidance or consensus standards that might be needed to assist operators in implementing any integrity management requirements. This phase will include consideration of a multi-faceted set of potential approaches, including regulations and guidance, but will also consider a national education program, development of new inspection technologies, and legislative models that states could adopt. The second phase, to begin in January 2006, will include development of appropriate requirements by OPS and preparation of guidance/standards by appropriate bodies. 1 House of Representatives Report 108-792, November 20, 2004. 2 “Progress and Challenges in Improving Pipeline Safety,” Statement of the Honorable Kenneth M. Mead, Inspector General, Department of Transportation, before the Committee on Energy and Commerce, Subcommittee on Energy and Air Quality, U. S. House of Representatives, July 20, 2004. <<>> A Report to the Congress: Assuring the Integrity of Gas 2 Distribution Pipeline Systems 1. Program Overview The DOT Inspector General, in testimony before Congress in July 2004,3 recommended that OPS should define an approach for requiring operators of distribution pipeline systems to implement some form of integrity management or enhanced safety program with elements similar to those required in hazardous liquid and gas transmission pipeline integrity management programs. The Appropriations Committee asked OPS “to report to the House and Senate Committees on Appropriations by May 1, 2005, detailing the extent to which integrity management plan [IMP] elements may be applied to the natural gas distribution pipeline industry in order to enhance distribution system safety”.4 Industry and government have long been committed to the safe operation of the Nation’s 1.9 million miles of natural gas distribution pipelines. Building on the existing set of requirements, regulators and pipeline operators continue to examine natural gas distribution practices to understand the most effective approaches to improving the integrity and safety of these systems. During the past five years, OPS (as part of PHMSA) has promulgated regulations designed to improve the integrity of liquid and gas transmission pipelines. Together with our State partners, PHMSA has undertaken inspection of the programs by which operators are implementing these regulations. Implementation of these regulations has led both to improvements in the operators’ knowledge of their pipelines, and to identification and repair of thousands of defects in these pipelines. OPS also regulates distribution pipeline systems.5 Pursuant to agreements among OPS and the States, state inspectors perform most of the inspection and enforcement of the pipeline safety regulations on gas distribution systems. OPS ensures that State programs provide safety oversight in compliance with the Federal pipeline safety regulations. OPS and our State partners developed a program through which we will thoroughly reexamine means for strengthening the safety of distribution pipeline systems. This program will address the three elements of the strategy described by the DOT Inspector General: (a) understanding the infrastructure; (b) identifying and characterizing the threats; and (c) determining how best to manage the known risks (prevention, detection and mitigation). These three elements are essentially the same as those underlying the transmission pipeline integrity management regulations. The program will provide the basis for establishing integrity management requirements for distribution pipeline systems. These requirements must be different than those that have been applied to hazardous liquid and gas transmission 3 Ibid. 4 House of Representatives Report 108-792, November 20, 2004. 5 Gas transmission pipelines transport gas from areas where it is produced to areas where it is consumed. These pipelines are generally steel, of large diameter, operate at high pressures, and traverse long distances, sometimes more than 1,000 miles. Distribution pipeline systems are the network of pipes in communities that provide gas directly to consumers. They consist of small diameter pipelines, operating at low pressure, and constructed of a variety of materials. Distribution pipelines exist as a network with many branches in short distances (e.g., a service line connection for each house on a city street). The differences between the two types of pipelines can lead to a need to use different approaches to assuring safety, as described in this report. <<>> A Report to the Congress: Assuring the Integrity of Gas 3 Distribution Pipeline Systems pipelines, because the models and tools prescribed by those regulations have only very limited applicability to distribution pipeline systems. The program presented in this Report was designed to identify opportunities for improving the safety of distribution pipeline systems. Our analysis of the past few years of data identified that in order to address safety threats to distribution pipelines, there are a number of target audiences that PHMSA needs to involve in developing strategies to reduce these threats. Accordingly, OPS is involving a larger number of key stakeholder groups than contacted in the past, including State and Federal regulators, representatives from the spectrum of distribution operators, interested members of the public, and representatives of our Nation’s fire service. These participants are organized into work/study groups that will gather and analyze data to help focus the effort and ultimately identify options for attaining improved safety. In addition, OPS will be posting information on a public web site as the program activities progress, to offer an opportunity for other interested members of the public to comment. OPS organized the program in two major phases. During the remainder of 2005 (Phase 1) work/study groups will gather and analyze data, and develop the elements of a safety improvement program. During the following year (Phase 2) OPS and pipeline standards development organizations (if needed) will work to develop requirements, guidelines and standards that will be implemented using some combination of four options favored by a consensus of the stakeholder group. • The first option is a high level, risk-based, performance-oriented Federal regulation. • The second option is supplemental information through one or more guidelines or national consensus standards describing choices on how the spectrum of distribution pipeline operators might apply fundamental risk-based principles to achieve the desired improvements. States would then have the opportunity to draw on the standards and guidance to promulgate regulations describing how the unique set of operators they regulate should implement improvements satisfying the Federal requirements. • Third is a structured nation-wide education program on preventing excavation damage, focused on the new 811 one-call program. • The final option is development of innovative safety technologies capable of producing observable safety improvements. The requirements that may result from this program could prove expensive for operators to implement. The view of an executive steering group6 was that it is important to consider all costs related to new efforts to prevent and mitigate distribution line incidents together, in order to assure the most cost-effective solution. Thus, the group emphasized the importance of evaluating all options for preventing, detecting and mitigating threats to public safety consistently. For example, the group indicated its preference that use of excess flow valves (EFVs) as a means of mitigating the impact of severed gas distribution lines should be 6 See Section 6 for a description of the groups involved in the Action Plan <<>> A Report to the Congress: Assuring the Integrity of Gas 4 Distribution Pipeline Systems considered as part of the overall distribution safety improvement program, rather than being addressed in a separate Federal mandate. 2. Regulation of Distribution Systems and the Role of State/Federal Governments The principal authority for regulating the safety of gas distribution pipeline systems is exercised by State governments. Under 49 USC 60105 and 60106, States may exercise jurisdiction if their pipeline safety programs are certified by the DOT or if they enter into an agreement with DOT absent certification. At this time, all States except Alaska and Hawaii exercise safety jurisdiction under these provisions. States have a variety of ways in which they can oversee distribution pipeline safety. They can simply mirror the Federal pipeline safety program. They can impose additional requirements, beyond the Federal minimum. They can engage in special oversight programs with individual operators or groups of operators. Finally, they can provide incentives for safety improvements, often through their rate-setting authority. The Federal government has ultimate responsibility in regulating intrastate distribution pipeline operators. The Federal standards in 49 CFR Part 192 establish a minimum set of safety requirements that all states must implement. The DOT also collects data concerning distribution system mileage, incidents that occur on systems, their leak repair experience and other information about the size, age and material(s) of construction of their distribution piping. Initial consideration of an approach to integrity management for distribution pipeline systems will seek to identify changes that could be made in DOT data collection that would help improve the ability of State and Federal regulators to analyze and more clearly understand distribution system’s operating experience. The Office of Pipeline Safety will define further what improvements are needed and will determine if changes to its data collection forms are needed. OPS provides funding for the operation of State pipeline safety programs through a grant program that funds States’ oversight efforts. OPS has, in the past, identified emphasis areas for State focus in their oversight programs. These emphasis areas have included content of state regulations, pursuit of special initiatives, approaches to inspection of operators, and data collection and reporting. OPS can adjust its criteria for state funding grants to assure that appropriate emphasis exists in each State’s program. One area for special grant allocation resources is damage prevention – being proactive to reduce the likelihood that distribution pipelines will be damaged during excavation work. (This is a principal threat to the integrity of distribution pipelines). OPS is also engaged in work with state fire marshals, and has included a representative of this community in the distribution integrity management program. Representatives of public interest groups are also involved in helping to define the appropriate approaches to assuring distribution system integrity. This inclusiveness demonstrates the willingness of OPS and States to go beyond previous efforts to improve the assurance of distribution pipeline system safety. The OPS will also seek other input through posting documents related to this program on a web site. <<>> A Report to the Congress: Assuring the Integrity of Gas 5 Distribution Pipeline Systems It is appropriate that the principal actions for regulating distribution pipeline safety rest with the States. States need to balance safety and affordability. They need to assure that the particular needs of their citizenry are fulfilled. They also need to assure that the safety standards being applied are appropriate for the unique environment in which gas distribution occurs. Distribution pipeline systems are limited in geographic scope. The environment in which they operate significantly affects the safety issues that they face. Factors such as weather (dry/wet, hot/subject to freezing), soil conditions (corrosivity), and the local economy (significant construction and excavation activity) can significantly shape the threats affecting individual distribution operators and the actions necessary to address those threats. Proximity to gas producing regions also can be important, as natural gas that is distributed near production areas may be subject to little processing and may contain more contaminants, with potential to affect system integrity, than gas that is processed for long-distance transportation. States must have flexibility to deal with their local circumstances. It would be both ineffective and inefficient, for example, to impose requirements intended to address frost heave damage in the desert southwest. Integrity management requirements for distribution pipeline systems will be structured in a manner that allows States the necessary flexibility in implementation. 3. The Gas Distribution Safety Baseline In order to know what opportunities there are to enhance distribution pipeline safety, we must first examine where and how operators are performing today. There is very significant diversity among gas distribution pipeline operators in the United States. The size and technical depth of operators of distribution pipeline systems, the nature of the systems they operate, the requirements they must meet, and the practices that they use to assure safety all vary widely. An understanding of these differences, and the current approach to sharing and using practices that go beyond the regulations, i.e., the “baseline” level of program management, will be useful in understanding the approach being taken to enhance distribution integrity management. Diversity of Operators Operators of distribution pipeline systems subject to OPS/State safety regulation are of four different types: • Master meter systems (e.g., trailer parks, individual multi-occupancy buildings) • Publicly owned (e.g., town/city/county) municipal utilities • Investor-owned utilities • Propane gas distribution systems The order within this list represents the prevalence of each type of operator. There are approximately 1,000 publicly owned utilities delivering gas to consumers in the United States. By contrast, there are approximately 250 investor-owned utilities engaged in this business. <<>> A Report to the Congress: Assuring the Integrity of Gas 6 Distribution Pipeline Systems There are several thousand master meter operators and a few hundred liquid propane (LP) gas systems that are subject to the safety regulations in 49 CFR Part 192. Figure 1 - Distribution systems subject to 49 CFR 192 (Prepared by APGA from E IA data) # of systems 500 450 400 350 300 250 200 150 100 50 0 438 354 Municipal Investor-owned 96 59 69 50 35 20 6 0 10 < 100 100-1000 1000-10000 10000-100000 100000-1 million > 1 million # of customers (from EIA Form 176) Note: EIA does not maintain data on the number of customers served by master meter systems or liquid propane (LP) gas systems. There are several thousand master meter operators, the vast majority of which serve less than 100 customers. There are approximately 200 LP gas systems most of which also serve less than 100 customers. Within each of these groups, the size of individual operators also varies widely, as shown in Figure 1. Publicly-owned utilities tend to be smaller, with a majority serving less than 1,000 customers. In general, investor-owned utilities tend to be larger, with slightly over 100 companies serving more than 100,000 customers each. There are examples, though, of publicly owned utilities serving 100,000 customers and of investor-owned companies serving less than 1,000. The variability makes it difficult to generalize regarding these groups. The particular circumstances of each operator must be taken into account. Master meter operators are businesses such as apartment complexes, or mobile home or trailer parks, or are government entities like housing authorities and universities that receive gas from an outside supplier and distribute it via pipelines located within their facilities. These operators are generally small, with a large majority serving fewer than 100 customers. Distribution of gas, or operation of the distribution systems, is not their principal business. Propane system operators subject to pipeline regulation are also small. Propane used in individual installations, such as a rural farm with its own propane tank, is not subject to regulation as a pipeline system. Propane systems become subject to regulation when they distribute gas, by pipeline, to 10 or more customers. The large majority of these systems likely serve fewer than 100 customers. <<>> A Report to the Congress: Assuring the Integrity of Gas 7 Distribution Pipeline Systems Diversity of Infrastructure The pipeline systems operated by these operators are also subject to much variation. Natural gas has been distributed by pipeline in some areas for over a hundred years. Pipeline systems in these areas were originally small, serving a few customers. These systems merged as larger distribution companies were formed. The materials in use in some of these systems reflect older (e.g., cast iron, copper, bare steel) as well as newer (e.g., polyethylene plastic and cathodically protected coated steel) technology. In other areas, distribution of natural gas by pipeline is a relatively new phenomenon. In some rural areas, for example, gas may not have been available until a transmission pipeline was routed into the vicinity. Then, municipalities or distribution companies may have created a distribution system to bring natural gas service to customers for whom it was previously unavailable. Systems of this nature tend to be relatively uniform in age and type of materials, but the threats to integrity (such as electrical interference from other buried substructures and localized flooding or vehicular traffic patterns) may still vary from one location to another. Additional diversity will likely be introduced as systems age, new customers are added, and portions of the original systems are replaced. Individual master meter systems and propane systems tend to be relatively uniform due to their small size and limited geographical extent. Existing Regulations and Practices The Federal pipeline safety standards in 49 CFR Part 192 provide a common base of requirements applicable to distribution pipeline systems. These standards address design, construction and operation of pipeline systems as well as requirements affecting inspection, maintenance, repair and testing and also qualification of pipeline operations personnel. States are required to adopt these standards as one of the criteria for certifying their pipeline safety programs or for entering into an agreement with OPS to exercise safety jurisdiction. States can, and do, impose additional requirements where appropriate. The National Association of Pipeline Safety Representatives (NAPSR) is an organization consisting of the senior regulatory program manager from each State that exercises pipeline safety jurisdiction. NAPSR recently conducted a survey of its members to identify the extent of additional State requirements that go beyond Part 192. The survey identified that most States impose some additional requirements. A majority impose stricter criteria for reporting incidents and/or requires that operators notify the regulator of construction or testing that would provide an opportunity for the regulator to examine the pipeline and observe safety- significant work. These type of requirements reflect the close oversight relationship that exists between most state regulatory programs and the operators they regulate. State regulators generally interact routinely with operators under their jurisdiction, and therefore know their systems and personnel. States are actively engaged, on a daily basis, in overseeing safe operations. Additionally, approximately 25 percent of the States impose requirements for leak surveys beyond those required in Part 192. <<>> A Report to the Congress: Assuring the Integrity of Gas 8 Distribution Pipeline Systems The NAPSR survey also identified that approximately 65 percent of States have a program to replace some types of distribution piping. This may include cast iron pipe, uncoated and unprotected steel pipe, or certain types of plastic pipe that have been found to be subject to deterioration in service. The replacement programs vary in scope. In some cases, they involve all (or nearly all) of the operators in a State. In other cases, they may involve individual operators and may have been initiated as a result of an incident or event that highlighted problems associated with the aging material. A summary of the NAPSR survey results is included as Attachment 1 to this report. In addition to the NAPSR survey, OPS contacted several larger investor-owned utilities to obtain information about their safety practices that exceed minimum regulatory requirements. The operators surveyed, all of which serve mid- to large-sized cities, all reported that they use risk evaluation to help direct work on their pipelines. This supports a conclusion of the American Gas Foundation (AGF) that 82% of companies they surveyed use risk control practices.7 Use of risk models is not currently required of distribution system operators. Neither OPS nor States have audited these models or their application. We therefore cannot comment yet on the thoroughness of the approaches used, but note with satisfaction that the concept of using an estimate of risk to manage safety activities is becoming widely prevalent. OPS’ discussions also identified that the larger operators all had pipe management programs that included replacing portions of their system: where problems had been experienced identifying materials susceptible to failure; where certain construction practices potentially leading to problems may have been used; that include their older pipelines; or based on estimated risk. Again, this reinforces the AGF conclusion that 65% of surveyed companies had replacement programs.8 (It should be noted that replacement of pipe in highly built-up urban areas can be difficult due to the number and complexity of buried infrastructure facilities and the difficulty of working in the urban environment.) The operators contacted by OPS also perform leak surveys more frequently, based on unique operating conditions, than would be required by regulations and implement special practices to reduce third party damage. Most of the operators contacted by OPS also reported that they have elected to install excess flow valves (EFV) for new and replacement services, which goes beyond the regulatory requirement that customers be apprised of the availability of EFVs and that they be installed if the customer agrees to pay for them. The most prevalent safety practice followed by distribution system operators that is not required by Part 192 is membership in damage prevention programs, most often referred to as “one-call” programs. The AGF reports that over 95 percent of operators belong to such 7 American Gas Foundation, “Safety Performance and Integrity of the Natural Gas Distribution Infrastructure”, January 2005, p. 5-11. 8 Ibid, p. 5-13. <<>> A Report to the Congress: Assuring the Integrity of Gas 9 Distribution Pipeline Systems programs.9 Most states require gas utilities to belong to one-call programs. The breadth of participation in these activities provides a basis to presume that excavation damage incidents can be reduced. However, unfortunately, these incidents continue to occur. They are undoubtedly less prevalent than they would be in the absence of one-call programs, but they still represent a threat to distribution pipeline systems. This program will specifically include a review of industry practices and other approaches to prevent or reduce damage to identify ways in which their effectiveness can be improved. Insights from Incident Data The principal source of information available about distribution pipeline system safety and integrity is the data resulting from incident reports submitted to OPS. These reports are filed by operators, pursuant to 49 CFR 191.9, and include events occurring on jurisdictional pipelines that involve either: 1) a death or personal injury necessitating in-patient hospitalization; 2) estimated property damage, including cost of gas lost, of the operator or others, or both, of $50,000 or more; or 3) events that are significant, in the judgment of the operator, even if neither of the other criteria is met or exceeded. OPS changed its incident report form in 2004 to require that the cause of incidents be reported more precisely. All incidents reported prior to that time were attributed by the reporting operator to one of five major causes, one of which was “other.” Using the revised forms, operators identify one of seven major causes, which are further subdivided into 25 second- level causes. This change is intended to improve our understanding of the factors that result in gas pipeline incidents. The set of incident data submitted by operators represents significant problems that occur on the pipeline. It does not include all events involving or exacerbated by natural gas from distribution pipeline systems. For example, problems with an appliance in a customer’s home could result in an accumulation of gas, an explosion, and fire, potentially resulting in injury or death. Although the media may report such events as gas pipeline incidents, they are not. OPS has no regulatory authority over customer-owned piping or gas appliances, and operators are not required to report such events to OPS. Customer piping within homes and businesses is regulated by local building codes, often based on the National Fuel Gas Code or other model codes. There have been two recent studies that considered recent distribution incident experience. One was conducted by the AGF, under the oversight of a committee formed of representatives from AGF members and state pipeline safety regulators. The results of this study were reported in “Safety Performance and Integrity of the Natural Gas Distribution Infrastructure,” published by AGF in January 2005. The other was performed by Allegro Energy Consulting, in late 2004, under contract to OPS. The AGF study covered the period from 1990 to 2002. During that period, AGF found a statistically significant downward trend in “serious” incidents, defined as those involving a 9 Ibid, p. 5-12. <<>> A Report to the Congress: Assuring the Integrity of Gas Distribution Pipeline Systems 10 death or injury. (AGF chose to focus on these incidents because the reporting criteria are not as subjective as “significant to the operator” nor do local economic factors or inflation affect reporting of an event wherever or whenever it occurs.) The AGF concluded there were approximately 1.6 serious incidents per 100,000 miles of distribution pipeline during 2002. The AGF study identified that nearly half of the serious incidents occurring during the study period were a result of outside force damage. The only other cause category contributing to more than 10 percent of serious incidents was “other” which was responsible for almost 27 percent. The Allegro study re-evaluated five years of incident report data (1999-2003) to re-classify them to the new cause categories. This was accomplished by reviewing the narrative description of the incident that the operator provided when submitting the original report. Allegro considered 634 incidents reported in the five-year period. One third of them involved death or injury, i.e., would have been considered “serious” incidents by the AGF study. Nearly one half were reported due to the cost of damages alone. Six percent of the incidents apparently did not meet any of the reporting criteria, but they were still retained in the Allegro analysis. Allegro’s re-classification was successful in reducing the number of incidents for which the cause could not be attributed from the 27 percent noted in the AGF study to 12 percent. Allegro further found that a large majority of the incidents (67%) were caused by outside force damage. The new cause categories permitted Allegro to break the outside force damage category down into several components. Thirty-eight percent of the incidents were caused by excavation and mechanical damage (the vast majority caused by third parties), but 29 percent were caused by other sources of outside force. This new category included two major components: “fire first” and vehicle damage, each representing 11 percent of the total number of incidents. The fire first events represent incidents in which a building was on fire and the operator responded, but the fire was not caused by a gas leak. In many cases, the gas supply system in the building is compromised or damaged by the fire and contributes to its intensity until the gas can be shut off. Fire first incidents are not caused by problems in the gas distribution system and cannot be addressed in a distribution integrity management program. The vehicle-related events represent incidents in which a vehicle impacts a portion of the pipeline system, often the above-ground meter assembly. The accidents resulted from multiple causes, including drivers operating their vehicles while intoxicated and unattended vehicles rolling into the pipeline system. Allegro found that this category of incidents, while representing 11 percent of all incidents, involved 25 percent of the fatal incidents over the period studied. Thus, these data tell us that 1 out of 4 of the fatal incidents during this period could not have been prevented by any preventive action taken on the pipeline. Reducing the number of these incidents is likely to require actions that affect persons not under the regulatory jurisdiction of OPS or State pipeline regulatory authorities, i.e., vehicle operators. A summary of the Allegro report is included as Attachment 2. <<>> A Report to the Congress: Assuring the Integrity of Gas Distribution Pipeline Systems 11 Innovative Practices The American Gas Association (AGA) each year sponsors groups from among its members to identify innovative practices that they employ to improve operational performance and safety. These groups typically evaluate approximately five topic areas (e.g., damage prevention, main and service replacement, system reliability). In each area, practices of member companies are shared, innovative practices are identified, and the information is exchanged with participants at a roundtable forum. Detailed information is available only to companies that have participated in the groups. These forums serve a useful purpose and can contribute to expanding the understanding and application of innovative practices. This expansion can occur among participants, which are generally the larger, investor-owned companies. The results of these efforts are not available to operators that do not directly participate in the program, particularly publicly-owned operators that are not usually members of AGA. OPS believes that these activities have a positive impact on the reduction of incidents disproportionate to the percentage of operators that participate. There are two reasons for believing this: the large-operator participants operate a much larger percentage of the total distribution pipeline mileage than their numbers might suggest; and smaller operators, particularly those with only a few persons on staff and a limited amount of pipeline mileage, generally have much better detailed knowledge of their systems and the issues that affect them. Nevertheless, the impact of these activities is limited. Participation is not available to municipal operators who are not AGA members and often lack the staff resources necessary to become involved in this kind of outside activity. Also, not all AGA members participate in these activities. Monitoring the Effectiveness of Actions It is important that the effectiveness of whatever actions are taken to improve distribution pipeline safety be monitored. The ultimate measure of distribution pipeline system safety is the number of deaths and injuries and the amount of property damage caused by incidents on distribution pipeline systems. Fortunately, however, incidents occur relatively infrequently. Other interim measures are needed to evaluate the effectiveness of any new integrity management requirements implemented for distribution pipeline systems. An interim measure might be how any new regulatory initiatives impact system operators (e.g., the number of assessments or repairs that have been conducted is an interim measure of the effectiveness of the hazardous liquid and gas transmission integrity management rules). The program described in this report includes development of a way to measure these impacts and to develop a baseline from which improvements can be measured. <<>> A Report to the Congress: Assuring the Integrity of Gas Distribution Pipeline Systems 12 4. Evaluation of Applicability of Transmission IM Program and Practices OPS promulgated regulations in recent years requiring that pipeline operators (other than distribution pipeline operators) implement integrity management programs. These regulations apply to operators of hazardous liquid pipelines (49 CFR 195.452, published at 65 FR 75378 and 67 FR 2136) and to operators of gas transmission pipelines (49 CFR 192, Subpart O, published at 68 FR 69778). It is reasonable to ask why the same techniques used in these regulations cannot simply be applied to gas distribution pipeline systems. Both regulations set requirements for making best use of information to set safety priorities and to perform continuous evaluations. Integrity Management Elements The integrity management regulations for hazardous liquid and gas transmission pipelines are similar. Both require that operators identify segments of their pipeline where an incident could create high consequences. Both require that operators implem - **truncated:** true - **body characters:** 118915