# Pipeline Safety: Integrity Management Program for Gas Distribution Pipelines

- **operation:** document
- **citation:** 73 FR 36015
- **title:** Pipeline Safety: Integrity Management Program for Gas Distribution Pipelines
- **source type:** rulemaking
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** proposed
- **official:** true
- **published on:** 2008-06-25
- **effective on:** Not available
- **summary:** PHMSA proposes to amend the Federal Pipeline Safety Regulations to require operators of gas distribution pipelines to develop and implement integrity management (IM) programs. The purpose of these programs is to enhance safety by identifying and reducing pipeline integrity risks. The IM programs required by the proposed rule would be similar to those currently required for gas transmission pipelines, but tailored to reflect the differences in and among distribution systems. In accordance with Federal law, the proposed rule would require operators to install excess flow valves on certain new and replaced residential service lines, subject to feasibility criteria outlined in the rule. Based on the required risk assessments and enhanced controls, the proposed rule also would establish procedures and standards permitting risk-based adjustment of prescribed intervals for leak detection surveys and other fixed-interval requirements in the agency's existing regulations for gas distribution pipelines. To further minimize regulatory burdens, the proposed rule would establish simpler requirements for master meter and liquefied petroleum gas (LPG) operators, reflecting the relatively lower risk of these small pipeline systems. This proposal also addresses statutory mandates and recommendations from the DOT's Office of the Inspector General (OIG) and stakeholder groups.
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- **source url:** https://www.federalregister.gov/documents/2008/06/25/08-1387/pipeline-safety-integrity-management-program-for-gas-distribution-pipelines
**body:**

Federal Register, Volume 73 Issue 123 (Wednesday, June 25, 2008) [Federal Register Volume 73, Number 123 (Wednesday, June 25, 2008)] [Proposed Rules] [Pages 36015-36034] From the Federal Register Online via the Government Publishing Office [ www.gpo.gov ] [FR Doc No: 08-1387] ======================================================================= ----------------------------------------------------------------------- DEPARTMENT OF TRANSPORTATION Pipeline and Hazardous Materials Safety Administration 49 CFR Part 192 [Docket No. PHMSA-RSPA-2004-19854] RIN 2137-AE15 Pipeline Safety: Integrity Management Program for Gas Distribution Pipelines AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA), Department of Transportation (DOT). ACTION: Notice of proposed rulemaking. ----------------------------------------------------------------------- SUMMARY: PHMSA proposes to amend the Federal Pipeline Safety Regulations to require operators of gas distribution pipelines to develop and implement integrity management (IM) programs. The purpose of these programs is to enhance safety by identifying and reducing pipeline integrity risks. The IM programs required by the proposed rule would be similar to those currently required for gas transmission pipelines, but tailored to reflect the differences in and among distribution systems. In accordance with Federal law, the proposed rule would require operators to install excess flow valves on certain new and replaced residential service lines, subject to feasibility criteria outlined in the rule. Based on the required risk assessments and enhanced controls, the proposed rule also would establish procedures and standards permitting risk-based adjustment of prescribed intervals for leak detection surveys and other fixed-interval requirements in the agency's existing regulations for gas distribution pipelines. To further minimize regulatory burdens, the proposed rule would establish simpler requirements for master meter and liquefied petroleum gas (LPG) operators, reflecting the relatively lower risk of these small pipeline systems. This proposal also addresses statutory mandates and recommendations from the DOT's Office of the Inspector General (OIG) and stakeholder groups. DATES: Anyone may submit written comments on proposed regulatory changes by September 23, 2008. PHMSA will consider late-filed comments to the extent possible. ADDRESSES: Comments should reference Docket No. PHMSA-RSPA-2004-19854 and may be submitted in the following ways: E-Gov Web Site: http://www.regulations.gov . This site allows the public to enter comments on any Federal Register notice issued by any agency. Fax: 1-202-493-2251. Mail: DOT Docket Operations Facility (M-30), U.S. Department of Transportation, West Building, 1200 New Jersey Avenue SE., Washington, DC 20590. Hand Delivery: DOT Docket Operations Facility, U.S. Department of Transportation, West Building, Room W12-140, 1200 New Jersey Avenue SE., Washington, DC 20590 between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. [[Page 36016]] Instructions: In the E-Gov Web site: http://www.regulations.gov , under ``Search Documents'' select ``Pipeline and Hazardous Materials Safety Administration.'' Next, select ``Notices,'' and then click ``Submit.'' Select this rulemaking by clicking on the docket number listed above. Submit your comment by clicking the yellow bubble in the right column then following the instructions. Identify docket number PHMSA-RSPA-2004-19854 at the beginning of your comments. For comments by mail, please provide two copies. To receive PHMSA's confirmation receipt, include a self-addressed stamped postcard. Internet users may access all comments at http://www.regulations.gov , by following the steps above. Note: PHMSA will post all comments without changes or edits to http://www.regulations.gov including any personal information provided. Privacy Act Statement Anyone can search the electronic form of all comments received in response to any of our dockets by the name of the individual submitting the comment (or signing the comment, if submitted on behalf of an association, business, labor union, etc.). DOT's complete Privacy Act Statement was published in the Federal Register on April 11, 2000 (65 FR 19477). FOR FURTHER INFORMATION CONTACT: Mike Israni at (202) 366-4571 or by e- mail at [email protected] . SUPPLEMENTARY INFORMATION: The following subjects are addressed in this preamble: I. Background A. Integrity Management (IM) B. Nature of U.S. Distribution Pipeline Systems C. Safety of Distribution Pipeline Systems D. Distribution Pipeline Safety Regulation E. Applicability of Integrity Management Plans (IMP) to Distribution Pipeline Systems Distribution Systems Are Located in Highly Populated Areas Challenges of Assessment or Testing II. American Gas Foundation Study III. Recommendations or Mandates of Oversight Bodies A. DOT Inspector General B. National Transportation Safety Board C. Congressional Mandate IV. Stakeholder Groups A. Stakeholder Groups' Involvement B. Stakeholder Groups' Findings C. Stakeholder Conclusions D. Findings Relevant To Leak Management E. Stakeholder Considerations Regarding Excess Flow Valves Comments From Fire Service Organizations V. Public Meetings A. Public Meetings Concerning Distribution Integrity Management B. EFV Public Meeting VI. Guidance for Integrity Management VII. Applicability to Small and Simple Distribution Systems; Request for Comments A. Master Meter and LPG Operators B. Very Small Distribution Systems VIII. Plastic Pipe Issues A. Plastic Pipeline Database and Availability of Failure Information B. Plastic Pipe Marking IX. Monitoring the Effectiveness of Actions X. Deviating From Required Intervals Based on Operator's Distribution Integrity Management Plan (DIMP) XI. Prevention Through People XII. Summary Description of Proposed Rule XIII. Section-by-Section Analysis XIV. Regulatory Analyses and Notices I. Background A. Integrity Management PHMSA is initiating this rulemaking proceeding in order to extend its integrity management approach to the largest segment of the Nation's pipeline network--the distribution systems that directly serve homes, schools, businesses, and other natural gas consumers. Beginning in 2000, the agency has promulgated regulations requiring operators of hazardous liquid pipelines (49 CFR 195.452, published at 65 FR 75378 and 67 FR 2136) and gas transmission pipelines (49 CFR 192, Subpart O, published at 68 FR 69778) to develop and follow individualized integrity management (IM) programs, in addition to PHMSA's core pipeline safety regulations. The IM approach was designed to promote continuous improvement in pipeline safety by requiring operators to identify and invest in risk control measures beyond core regulatory requirements. The IM regulations for hazardous liquid and gas transmission pipelines are similar. Fundamentally, both require that operators analyze their pipelines to identify and manage factors that affect risks to the pipeline and risks posed by the pipeline. Operators must integrate the best available information about their pipelines to inform their risk decisions. Both rules require that operators identify segments of their pipelines where an incident could cause serious consequences and focus priority attention in those areas. Both rules also require that operators implement a program to provide greater assurance of the integrity of these pipeline segments. Actions required in these segments include assessments utilizing in-line inspection tools, pressure testing, direct assessment, or other technology that provides an equivalent understanding of the pipe condition. While existing regulations required prompt repair of safety-significant problems, the IM regulations require operators to inspect their lines and perform repairs within a period of time commensurate with the safety significance of the problems found. The rules also require that operators implement measures that will help prevent accidents from occurring on their high-consequence segments and that will mitigate the consequences if an accident does occur. Although it is too early to draw statistically-significant conclusions about the effectiveness of the IM programs for transmission pipelines, early indications are very favorable. The initial inspections under IM have identified tens of thousands of locations where the pipelines were damaged (including damage by external force/ excavation and by conditions like corrosion) and repairs were made before accidents could occur. Operators have implemented additional safety measures to address higher-risk situations, many of which are unique to their individual circumstances. These early successes have fueled interest in extending the IM approach to gas distribution pipeline systems. B. Nature of U.S. Distribution Pipeline Systems As of 2006, more than 1.2 million miles of gas mains are in service in the U.S. ``Mains'' are the pipelines providing a common supply to a certain number (often hundreds) of homes and businesses. These pipelines are often located under city streets and range in size from less than 2 inches in diameter to more than 8 inches in diameter. These mains feed over 63 million ``services.'' A ``service'' is the pipe that connects to a main and delivers gas to an individual customer, at the meter. Service lines are usually very small, less than 1-inch in diameter except for those serving larger industrial and commercial customers. The length of service lines varies widely. In dense urban areas where townhouses are built right up to the sidewalk, a service line may be only a few feet long. In rural areas, service lines may be several hundred feet long, perhaps as long as a mile. PHMSA uses 65 feet as its estimate of the average length of a service line. Applying that value, the 63 million services represent nearly another 800,000 miles of pipeline, meaning that the total amount of pipeline in U.S. distribution pipeline systems is approximately two million miles. Use of natural gas continues to grow in the U.S., and the amount of distribution pipeline in service increases accordingly. Since 2001, an additional 5.1 million customers have been added, representing an increase of [[Page 36017]] over 173,000 miles of distribution pipeline. 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 often 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) technologies. Two-thirds of States have programs that require distribution pipeline operators to replace older pipe,\1\ but much of the pipe in service is still many decades old. --------------------------------------------------------------------------- \1\ Some of these programs involve a limited number of operators, as described further below. --------------------------------------------------------------------------- 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. Diversity of the gas pipeline system will likely increase as systems age, new customers are added, and portions of the original systems are replaced. The bulk of newer gas distribution pipeline systems, and replacements for older pipe, are comprised of plastic pipe. More than half of the pipelines in U.S. gas distribution systems are non-metallic. C. Safety of Distribution Pipeline Systems By operation of the Federal Pipeline Safety Laws, 49 U.S.C. 60102, the Federal government has assumed ultimate responsibility for the safety oversight of distribution pipeline operators. PHMSA's regulations in 49 CFR Part 192 establish a minimum set of safety requirements that all States must implement, although States may impose more stringent requirements on intrastate systems. PHMSA also collects data concerning distribution system mileage, incidents that occur on distribution systems, their leak repair experience and other information about the size, age and material(s) of construction of their distribution piping. PHMSA considered this information, its historical trends, and projected patterns in proposing IM regulations for distribution pipelines. Incidents on distribution pipelines kill and injure more people than incidents on gas transmission pipelines. As noted above, nearly two million miles of distribution pipelines are in operation in the U.S., compared with approximately 300,000 miles of gas transmission pipelines. In addition, distribution pipelines are almost all located in populated areas. Large portions of gas transmission pipelines traverse rural areas where there are few people. Largely because of these differences, incidents on distribution pipelines in 2006 resulted in five times as many fatalities (16 vs. 3) and six times as many serious injuries (25 vs. 4) as those on gas transmission pipelines, even though the total number of incidents on each type of pipeline was about the same (141 vs. 134). Because of the much larger number of miles of distribution pipeline, the normalized rate of fatalities and injuries (i.e., the number per 100,000 miles) is similar for the two types of lines, with a slightly lower rate for distribution lines. As described further below, the trend in gas distribution incidents involving fatalities and serious injuries (those requiring hospitalization) was downward from 1990-2002. In the years since, however, the number has again started to increase. D. Distribution Pipeline Safety Regulation Pursuant to Federal law, most oversight of gas distribution pipeline systems is performed directly by States. Under 49 U.S.C. 60105 and 60106, a State may exercise jurisdiction over intrastate gas distribution operations within the State if its pipeline safety program is certified by PHMSA or if it enters into an agency agreement with DOT. Under these provisions, 48 States (excluding only Alaska and Hawaii) and the District of Columbia currently exercise safety jurisdiction over some or all gas distribution operations within their boundaries. States must implement the minimum standards established by PHMSA but 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; or finally, they can provide incentives for safety improvements, often through their rate-setting authority. 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 ensure that the particular needs of their citizenry are fulfilled. They also need to ensure that the applied safety standards are appropriate for the unique environment in which gas distribution occurs. Distribution pipeline systems are limited in geographic scope, although some systems serve many thousands of customers. 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 less processing and may contain more contaminants, with greater 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 frost heave damage requirements in the desert southwest. States address these differences by imposing some requirements that exceed those in the Federal safety code. The National Association of Pipeline Safety Representatives (NAPSR)\2\ surveyed its members to determine the extent to which they impose requirements or programs that exceed the Federal minimum.\3\ The survey, addressed to each State pipeline safety program manager, asked whether the State imposes additional requirements or has infrastructure safety improvement programs implemented that exceed the federal minimum requirements. NAPSR asked its members to provide a brief description of any positive responses. --------------------------------------------------------------------------- \2\ NAPSR's members are the managers of the pipeline safety regulatory staff from each state (and the District of Columbia) that is certified by, or a designated agent of, DOT for regulatory oversight. \3\ NAPSR conducted the survey in 2004-2005. --------------------------------------------------------------------------- Forty-eight State agencies and the District of Columbia responded to the NAPSR survey. All but six reported some requirements or programs exceeding the Federal minimum standards. The results were as follows: 20 States have additional reporting requirements; [[Page 36018]] 11 States provide enhanced oversight and observation of work/testing on the pipelines; 11 States have additional damage prevention requirements; 13 States require additional leak testing; 11 States impose leak response requirements (including eight of the 13 that require additional leak testing); Eight States impose either additional odorant requirements or more frequent testing; Six States impose additional design and installation requirements; Six States impose additional training and qualification of operator personnel requirements. Six States impose additional requirements related to cathodic protection systems used to protect steel pipe from corrosion; Six States require their State regulators to approve operators' operating and maintenance plans; Five States impose operating pressure requirements; Five States impose additional customer meter requirements; Three States require that operators cap off abandoned service lines after specified periods; Four States extend operator responsibility for maintenance of service/customer lines; Four States encourage safety enhancement through rate cases, and approve the operation of distribution pipeline systems by specific companies; One State requires its operators to conduct an annual evaluation of all cast iron and unprotected steel pipe in their distribution systems; and One State requires its operators to remediate any evidence found of corrosion within 90 days. The most significant area in which States reported actions beyond Federal standards was replacement of aging and inferior infrastructure. Thirty-three States, or two-thirds of those responding, reported they have some kind of program for replacing infrastructure, including cast- iron pipe, uncoated steel pipe, copper pipe, and some types of plastic pipe. These programs varied in scope and schedule, often reflecting the relative amount of targeted infrastructure present in each State. NAPSR collected the following data on pipe replacement programs: Twelve States reported their programs involved all (or nearly all) operators; Sixteen States reported their programs involved one or a limited number of operators, often in response to past accidents or rate cases; Four States provided no information from which to estimate the scope of their programs; Eight States reported that their programs are complete (i.e., all targeted infrastructure has been replaced) or will be completed by 2010; Eight States reported that their programs will be complete by about 2020; Four States reported that their programs would not be complete until after 2020; and Twelve States did not report an expected completion date. These results indicate States can and do exercise authority beyond minimum Federal requirements. Additional requirements are focused in scope, and vary from State to State, based on local needs and issues. Programs to replace older, inferior infrastructure are the most widespread practice beyond Federal requirements. Such programs are in progress in two-thirds of the States, although some of these programs are of limited scope (i.e., affecting a single operator). Still, despite these State efforts, serious incidents continue to occur on distribution pipeline systems. As discussed above, the number of serious incidents per mile is similar to that for gas transmission pipelines, but there are many more miles of distribution pipelines. As a result, serious incidents on gas distribution pipelines kill or injure more people annually than do incidents on gas transmission pipelines. Even if the number of serious incidents on transmission pipelines is significantly reduced, major improvement in overall safety will not be achieved unless the number of incidents on distribution pipelines is also reduced. PHMSA's approach to achieving improvement for gas transmission pipelines was to require that each operator analyze its own pipeline's risks, through an integrity management program, and address them as necessary. PHMSA concludes that the same approach is appropriate for distribution pipelines. Although the additional State requirements provide protection beyond the minimum Federal standards to help assure the integrity of distribution pipeline systems, the requirements vary by State. No State requires a comprehensive systematic evaluation and management of the risks associated with operating gas distribution pipelines similar to PHMSA's existing IM requirements or to the requirements we are proposing in this Notice. Nevertheless, some State imposed requirements likely encompass individual actions operators would be required to take under an IM program, offsetting the costs for those operators to comply with this rule. The National Association of Regulatory Utility Commissioners (NARUC) has also considered the need for additional safety regulation. NARUC members represent Public Service/Safety Commissions under whose auspices States usually conduct pipeline safety regulatory programs. As such, NARUC represents executive management of State pipeline safety programs. In February 2005, the NARUC Board of Directors adopted a resolution encouraging development of an approach to distribution IM using risk-based, technically-sound, and cost-effective performance- based measures. NARUC recommended an approach based on the notion that operators are knowledgeable about their infrastructure and can identify and respond to threats against their systems in order to reduce the risk of system failures while balancing the need to ensure continued safe, reliable service at a minimal financial cost. NARUC based its resolution on the long-standing commitment of industry and government to operate the United States' gas pipeline system reliably and safely. They acknowledged recent examinations by regulators, legislators, and gas distribution pipeline operators to determine the most effective approach to maintaining and enhancing distribution system integrity and safety. NARUC commented that States must take into account varying circumstances including: geography, energy customer base, local economy, system age and construction materials, size of distribution operations and consumption patterns of gas customers (ranging from large-volume manufacturers to mid-size businesses to single-family residences), as well as a State's overall executive policies and goals. NARUC noted that due to significant structural, geographical, and functional differences among gas transmission and distribution companies, it would be infeasible to apply many transmission integrity requirements to distribution systems. NARUC further noted any adjustment to an operator's distribution IM program should be responsive to the operator's safety performance, existing regulations, and current practices affecting such performance. E. Applicability of Integrity Management Plans (IMP) to Distribution Pipeline Systems The basic premise of the integrity management programs for gas transmission and hazardous liquid [[Page 36019]] pipelines--that safety is improved by identifying risks and taking actions to address them--is applicable to distribution pipeline systems. However, because of the differences between distribution pipeline systems and pipeline systems covered by current IM regulations, the physical inspections (e.g. In-Line Inspection tools and Direct Assessment methods) of pipeline segments required by the current IM regulations cannot be required on distribution pipelines. Because the same IM regulations will not work, a different type of integrity management approach is necessary. Distribution Systems Are Located in Highly Populated Areas The first element of existing IM program requirements for transmission pipelines is to identify so-called ``high consequence areas''--those segments of the pipeline where an incident/break could produce serious harm to people or the environment. This is important for hazardous liquid and gas transmission pipelines because both traverse large distances, including areas that are sparsely populated or where risk of serious environmental damage would be small. Identifying high consequence areas improves the effectiveness of integrity management requirements by focusing inspection and assessment efforts on the pipe where significant consequences could occur. As described above, gas distribution pipeline systems are different. Unlike transmission pipelines, they do not traverse long distances and generally do not include significant areas of limited population. They operate almost entirely in populated areas, because their purpose is to provide gas service to the residences and businesses of those populations. Thus, by contrast to a transmission pipeline, identifying areas where the gas distribution pipeline is near concentrations of people would not tend to identify a limited portion of the pipeline on which integrity management attention should be focused. Some other means of prioritizing operator attention, based on risk, is needed for distribution pipelines. Challenges of Assessment or Testing As described above, distribution pipeline systems consist of a complex network of mains and services. They include considerable lengths of pipeline of very small diameter and many non-metallic materials. They also include extensive branching, with a typical city main being connected to a new service roughly every one hundred feet. These differences make it impossible to use many of the techniques required by the existing IMP regulations to assess the physical condition of the pipeline. One technique (in-line inspection) involves passing through the inside of a pipeline inspection tools that use magnetic detection techniques to identify areas where the wall of a steel pipe has been thinned by corrosion or damage. Another (direct assessment) involves using indirect inspection tools to identify areas where the electrical current imposed on steel pipes to prevent corrosion is interrupted or is experiencing interference. Distribution pipelines are too small and have too many connections to allow in-line inspection tools to pass through the lines, and approximately half of the distribution pipeline system is non-metallic (e.g., plastic), meaning that neither the internal tools nor the indirect inspections used for direct assessment can be used. Pressure testing (isolating a pipe and filling it with water or air at high pressure to see if it leaks) can be used, but would require that service be cut off to all customers served by the portion of the system being tested. A continuing program of such testing would essentially constitute the natural gas equivalent of ``rolling blackouts'' and would be unacceptable to the American public. Distribution pipelines can be inspected by digging to expose the pipeline, and operators are required to do such inspections when pipe must be excavated for other reasons. Digging up all distribution pipelines on a periodic basis, however, is clearly impractical. For these reasons, the inspection requirements of current IMP regulations cannot be used for distribution pipelines. Some other approach is needed. As described below, PHMSA worked with stakeholder groups and held two public meetings to help determine how best to apply IMP principles in the gas distribution pipeline environment.\4\ These public meetings are discussed further below. --------------------------------------------------------------------------- \4\ The public meetings concerning integrity management requirements were held on December 16, 2004 and September 21, 2005. A third meeting, on June 17, 2005, focused exclusively on appropriate requirements for excess flow valves. Summaries of all meetings are in the docket. --------------------------------------------------------------------------- II. American Gas Foundation Study The gas distribution industry recognized the need to consider its safety record and to determine if additional actions are needed. In late 2003, the American Gas Foundation (AGF) launched a study of the safety performance and integrity of gas distribution pipeline systems. Currently, operators must report an incident to PHMSA if it meets the reporting criteria in 49 CFR Part 191. The AGF study examined the record of incidents reported to PHMSA on gas distribution pipeline systems from 1990 through 2002 (the latest year for which data were complete at the time the study began) and compared that record to incidents reported for transmission pipelines over the same period. The AGF study analyzed trends in reported incidents and focused specifically on incidents involving deaths or injuries requiring hospitalization (called ``serious incidents'' in the study). A joint team, the Distribution Infrastructure Government-Industry Team (DIGIT), was established to oversee the AGF study. This team consisted of representatives of the AGF, the American Public Gas Association, and State pipeline safety regulators. PHMSA took part in DIGIT as an observer. The AGF published its findings in January 2005.\5\ The AGF study found a downward trend in serious incidents over the 13-year period analyzed at a 95 percent statistical confidence level. (No statistically significant trend was found when considering all reported incidents.) The number of serious incidents per 100,000 miles of distribution pipeline was essentially the same as that for gas transmission pipelines over the analyzed period. There are many more miles of distribution pipelines, however. Historically, distribution pipeline incidents result in more deaths and injuries than incidents on gas transmission or hazardous liquid pipelines, largely because distribution lines are located in populated areas and constitute a much larger share of the mileage of working pipelines. --------------------------------------------------------------------------- \5\ American Gas Foundation, ``Safety Performance and Integrity of the Natural Gas Distribution Infrastructure,'' January 2005, available at http://www.aga.org/Template.cfm/Section=Non-AGA_Studies_Forecasts_Stats&template . --------------------------------------------------------------------------- AGF found the primary cause of serious incidents was outside force damage, principally third-party excavation. Outside force damage represented 47 percent of serious incidents over the analyzed period. Corrosion caused 6.5 percent of serious incidents, and all other causes contributed less than 10 percent each. AGF also examined practices gas distribution operators use to address threats to their systems, both those required by regulation and those performed voluntarily. The study found no obvious gaps and that industry practices exist to address known threats. Further, the study concluded (as for [[Page 36020]] hazardous liquid pipelines and gas transmission pipelines) serious incidents continue to occur (albeit rarely) despite compliance with existing regulations. III Recommendations or Mandates of Oversight Bodies A. DOT Inspector General In a report published June 14, 2004,\6\ the DOT's Inspector General (IG) found that recent accident trends for gas distribution pipelines are not favorable. The IG noted that nearly all of the natural gas distribution pipelines are located in highly-populated areas, such as business districts and residential communities, where a rupture could have the most significant consequences. As a result, the audit pointed out for the 10-year period from 1994 through 2003, accidents on natural gas distribution pipelines have resulted in more fatalities and injuries than accidents on hazardous liquid and natural gas transmission lines combined. --------------------------------------------------------------------------- \6\ Audit report SC-2004-064, issued June 14, 2004. --------------------------------------------------------------------------- The IG also recognized that applying risk management principles to distribution pipelines could help reverse these trends. In testimony before Congress in July 2004,\7\ the IG recommended that PHMSA 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. --------------------------------------------------------------------------- \7\ Id. --------------------------------------------------------------------------- B. National Transportation Safety Board The National Transportation Safety Board (NTSB) investigates serious pipeline accidents, including those that occur on gas distribution pipeline systems. Over the years, the NTSB has made several recommendations to improve safety regulation of gas distribution pipelines. In particular, the NTSB has recommended the use of excess flow valves (EFVs) in all new construction and replaced service pipelines. EFVs have received significant attention as a mitigation option for gas distribution systems. Current Federal regulations require that operators notify service line customers for new and replaced service lines of the availability and potential safety benefits of installing EFVs.\8\ In lieu of this notification, operators may elect to install the valves voluntarily when certain conditions apply. The valves are generally applicable for new installations or complete service piping replacement for single-family residential homes, where the operating pressure is greater than 10 pounds per square inch (psi). Operators must install the valve if the customer agrees to pay for the cost of such installation. Discussions with operators indicate that approximately 30% of distribution system operators are installing the valves as a routine part of new and replaced service installations in situations in which they apply. Many of these are larger distribution operators, so the percentage of new and replaced service line installations voluntarily including EFVs is higher. --------------------------------------------------------------------------- \8\ 49 CFR 192.383. --------------------------------------------------------------------------- PHMSA conducted additional studies on the effectiveness of the valves and on the experience that has been gained as a result of their use. NAPSR assisted in these studies. PHMSA concluded that EFVs, if specified and installed correctly, operate reliably to cut off the supply of gas in the event of major damage to the downstream service line (e.g., excavation damage). While performance problems had occurred with early installation of EFVs, the data also show that the valves seldom now suffer false activations, cutting off the supply of gas when no damage has occurred. EFVs installed in new construction or replaced service lines would mitigate an incident occurring on service lines in which the line was severed. The valves are designed to operate in the event of line ruptures that result in major flow of gas. At the same time, they are an inexpensive option for mitigating such incidents. The valves themselves cost less than $20 and the cost to install them, when a service line is being installed or replaced is nominal. They will not operate in the event of small leaks. They will not operate in the event of leaks or problems within a customer's residence or business, downstream of their pressure regulator, including situations in which a fire in a residence results in a breach of a gas appliance line in the residence. PHMSA asked Allegro Energy Consulting to review incident report records to estimate how many incidents might have been mitigated by the presence of an excess flow valve had one been installed at construction or during repair. Allegro reviewed 634 incident reports submitted between 1999 and 2003. They screened out those that did not involve service lines, that were obviously slow leaks, or which otherwise did not appear to meet the criteria as incidents for which an excess flow valve would be beneficial. As a result, Allegro identified 101 incidents in which the presence of an EFV might have mitigated consequences over this five-year period. To be clear, this is an estimate. The incident reports do not include some information (e.g., gas flow rate) that is necessary to ascertain definitively whether an excess flow valve would have been effective. They do not include information on whether the 25% of fatalities or injuries in which automobiles struck gas meter set assemblies at the side of homes could have been prevented by an EFV shutting off gas flow. PHMSA also conducted a public meeting concerning EFVs, which is described in Section VI below. C. Congressional Mandate Subsequent to the stakeholder groups' recommendations discussed below and the public meeting, Congress passed the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (PIPES Act), which the President signed into law in December 2006. The Act included a mandate that PHMSA require gas distribution operators to implement integrity management programs and to install EFVs in all new or replaced residential gas service lines where operating conditions are suitable for available valves, beginning June 1, 2008. This proposed rule includes requirements addressing this mandate, which will no longer require the customer notification requirements of Sec. 192.383. Thus, we are proposing to repeal this requirement. IV. Stakeholder Groups A. Stakeholder Groups' Involvement In 2004, as described above, the IG recommended that PHMSA establish IM requirements for distribution pipelines, including elements similar to those in the IM regulations for hazardous liquid and gas transmission pipelines (except for those related to physical inspection (i.e., assessment, of the pipeline). The IG highlighted this recommendation in testimony before Congress in 2004, and a report of the fiscal year (FY) 2005 Conference Committee on Appropriations required DOT to report its plans to est
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