The United States has a 295,000-mile network of natural gas transmission pipelines that are owned and operated by approximately 900 operators. These pipelines are important to the nation because they transport nearly all the natural gas used, which provides about a quarter of the nation’s energy supply. Gas transmission pipelines typically move gas products over long distances from sources to communities and are primarily interstate. They generally deliver natural gas to local distribution pipelines, which distribute the gas to commercial and residential end-users. Local distribution companies may also operate small portions of transmission pipelines. PHMSA administers the national regulatory program to ensure the safe transportation of natural gas and hazardous liquid by pipeline. In general, PHMSA retains full responsibility for inspecting and enforcing regulations on interstate pipelines, but it has arrangements with 48 states, the District of Columbia, and Puerto Rico to assist with overseeing intrastate pipelines. These states are currently authorized to receive reimbursement of up to 50 percent of the costs of their pipeline safety programs from PHMSA. Traditionally, PHMSA has carried out its oversight role using minimum safety standards that were uniformly applied to all pipelines based on the “class location” of the pipeline. A pipeline’s class location—based on factors such as population within 660 feet of the pipeline—determines the applicable standards such as the thickness of the pipe required and the pressure at which it can operate. The Pipeline Safety Improvement Act of 2002 modified PHMSA’s traditional oversight approach by supplementing the minimum standards with a risk-based program for gas transmission pipelines. This program—termed “integrity management”—requires gas transmission pipeline operators to assess and mitigate safety threats, such as leaks or ruptures due to incorrect operation or corrosion, to pipeline segments that are located in highly populated or frequently used areas, such as parks. Specifically, operators are required to perform baseline assessments on half of the pipeline mileage located in these areas by December 2007, and the remainder by December 2012. Those pipeline segments potentially facing the greatest risks of failure from leaks or ruptures are to be assessed first. As of December 2005 (latest data available), 447 gas pipeline operators reported to PHMSA that about 20,000 miles of their pipelines (about 7 percent of all gas transmission pipeline miles) lie in highly populated or frequently used areas. Individual operators reported that they have as many as about 1,600 miles and as few as 0.02 miles of pipeline in these areas. The 2002 act also requires that operators reassess these pipeline segments for safety threats at least every 7 years. Under flexibility provided by the act, PHMSA requires that operators reassess these pipeline segments for corrosion damage at least every 7 years in its implementing regulations, because corrosion is the most frequent cause of failures that can occur over time. (See fig. 1.) PHMSA’s regulations also incorporated, as mandatory, voluntary industry consensus standards on maximum reassessment intervals into these regulations for other types of safety threats. The industry standards require that operators reassess gas pipelines at least every 10, 15, or 20 years for all safety threats depending primarily on the condition of the pipelines and the pressure under which they operate. If conditions warrant, reassessments must occur more frequently. In addition, operators must perform prevention and mitigation activities—such as monitoring their pipelines for excavation or corrosion damage—on a continuing basis. Operators are making good progress in assessing and repairing their pipelines, thereby improving the safety of their pipeline systems. As of December 2005, operators had assessed about 6,700 miles of their 20,000 miles—or about 33 percent—of pipelines located in highly populated or frequently used areas. This progress indicates that they are well on their way to meeting the requirement to conduct baseline assessments on 50 percent of their pipelines in these areas by December 2007. In addition to assessing their pipelines, operators are also making progress in fulfilling the requirement to repair problems found on their pipelines in highly populated or frequently used areas. In the 2 years that operators have reported the results of integrity management, they have completed 340 repairs that were immediately required and another 1,981 scheduled repairs in highly populated or frequently used areas. While it is not possible to determine how many of these needed repairs would have been identified without integrity management, it is clear that the requirement to routinely assess pipelines enables operators to identify problems that may otherwise go undetected. Furthermore, the benefits of integrity management expand beyond highly populated or frequently used areas because a large number of operators are using internal inspection tools to assess their pipelines. These tools must be inserted and removed from the pipelines at designated locations that often run through other areas. Consequently, operators reported having assessed about 44,000 miles of pipelines located outside highly populated or frequently used areas, representing about 15 percent of all gas transmission pipelines. While operators are not required to report to PHMSA the results of these expanded assessments, operators we spoke with said that they plan to make necessary repairs identified through the assessments regardless of where they are identified. We estimate that the integrity management program should offer additional safety benefits over the minimum safety standards for up to 68 percent of the population living close to gas transmission pipelines. This estimate corresponds with PHMSA’s estimate of two-thirds of the population. A number of representatives from pipeline industry organizations, state pipeline agencies, safety advocate groups, and operators that we contacted agree that integrity management benefits public safety because it requires all operators to systematically assess their pipelines to gain a comprehensive knowledge about the risks to their pipeline systems. Other benefits cited by operators include improved communications within their companies and more strategic resource allocation. While the operators we contacted generally believe integrity management is beneficial, the program is not without its costs. For example, over half of the operators we spoke with said that they have hired additional staff or contractors as a result of the integrity management requirements. In addition, 19 of the operators we contacted (37 percent) were concerned about the level of documentation needed to support their gas integrity management programs. PHMSA requires operators to develop an integrity management program and provides a broad framework for the elements that should be included in the program. The regulations provide operators the flexibility to develop their programs to best suit their companies’ needs, but each operator must develop and document specific policies and procedures to demonstrate its commitment to compliance with and implementation of the integrity management program. Operators may use existing policies and procedures if they meet the requirements of integrity management. In addition, an operator must document any decisions made related to integrity management to demonstrate that it understands the threats to their pipelines and is systematically managing their pipelines for these threats. While the operators we contacted generally agreed with the need to document their policies and procedures, some said that the detailed documentation required for every decision is very time consuming and does not contribute to the safety of pipeline operations. In addition, a few operators expressed concern that they will not know if they have sufficient documentation until their programs have been inspected. Initial inspections of operators by PHMSA and state pipeline agencies have confirmed that some operators are experiencing difficulty with documentation but are generally doing well with assessments and repairs. According to PHMSA and state officials, as operators continue to develop and implement their integrity management programs and as they are provided feedback during inspections, the documentation issues identified during these initial inspections should be resolved. Another concern raised by 33 (65 percent) of the operators is the requirement to reassess their pipelines for corrosion problems at least every 7 years. This issue is discussed in the following section. Periodic reassessments of pipeline threats are beneficial because threats— such as the corrosive nature of the gas being transported—can change over time. However, the findings from baseline assessments conducted to date and the generally safe condition of gas transmission pipelines leads us to conclude that the 7-year requirement appears to be conservative. Through December 2005 (latest data available), 76 percent of the operators (182 of 241) reporting baseline assessment activity to PHMSA told the agency that their pipelines were in good condition, free of major defects, and requiring only minor repairs. (See fig. 2.) The remaining 59 operators found 340 problems requiring immediate repairs. About 60 percent of these problems occurred in seven operators’ pipelines. Since PHMSA does not require that operators tell it the nature of the problems found, we do not know how many, if any, were due to corrosion. These assessments covered about 6,700 miles, or about one-third of the nationwide total to be assessed. It is encouraging that the majority of operators nationwide reported that they found few or no problems requiring immediate repairs, because operators are supposed to assess pipeline segments facing the greatest risk of failure from leaks or ruptures first, as required by the 2002 act. In addition, since operators are required to identify and repair significant problems, the overall safety and condition of the pipeline system should be enhanced before reassessments begin toward the end of the decade. Regarding the industry’s overall safety record, over the past 5-1/2 years (from January 2001 through early July 2006), there were 143 corrosion- related incidents over the 295,000-mile transmission system (26 per year, on average)—none of which resulted in death or injury. Over the past 10- 1/2 years, 12 people have died and 3 have been injured in two corrosion- related incidents. Neither of these incidents occurred in a highly populated or frequently used area. About 80 percent of the 52 operators that we contacted prefer that reassessment intervals be based on the condition and characteristics of the pipeline segment rather than on a prescriptive standard. About half of these operators (28) expressed a preference for the industry consensus standard developed by the American Society of Mechanical Engineers (ASME B31.8S-2004) for setting reassessment intervals for time-dependent threats because it incorporates a risk-based approach (for pipeline failure) and is based on science and engineering knowledge. This standard sets reassessment intervals at a maximum of 10 years for high-stress pipeline segments, 15 years for medium-stress segments, and 20 years for low- stress segments.