On average, about 3 people have died and about 8 people have been injured annually over the last 10 years in natural gas transmission pipeline incidents. The number of incidents has increased from 77 in 1996 to 122 in 2004 and 200 in 2005, primarily due to the greater frequency of property damage. Much of this increase may be attributed to the rise in the price of gas (which has the effect of lowering the reporting threshold) over the past several years and to damage as a result of hurricanes in 2005. As a means of enhancing the security and safety of gas pipelines, the 2002 act included an integrity management structure that, in part, requires operators of gas transmission pipelines to systematically assess for safety risks the portions of their pipelines located in highly populated or frequently used areas, such as parks. Safety risks include corrosion, welding defects and failures, third-party damage (e.g., from excavation equipment), land movement, and incorrect operation. The act requires that operators perform these assessments (called baseline assessments) on half of the pipeline mileage in highly populated or frequented areas by December 2007 and the remainder by December 2012. Those pipeline segments potentially facing the greatest risks are to be assessed first. Operators must then repair or replace any defective pipelines. Performing this form of risk-based assessment is seen by many as having a greater potential to improve safety than focusing on compliance with safety standards regardless of the threat to pipeline safety. The act further provides that pipeline segments in highly populated or frequented areas must be reassessed for safety risks at least every 7 years. PHMSA’s regulations implemented the act by requiring that operators reassess their pipelines for corrosion damage every 7 years using an assessment technique called confirmatory direct assessment. Under these regulations, and mostly consistent with industry national consensus standards, operators must also reassess their pipeline segments for safety risks at least every 10, 15, or 20 years, depending on the pressure under which the pipeline segments are operated and the condition of the pipeline. There are about 900 operators of about 300,000 miles of gas transmission and gathering pipelines in the United States. As of December 2005, according to PHMSA, 429 of these operators reported that about 20,000 miles of their pipelines are located in highly populated or frequented areas (about 7 percent of all transmission pipeline miles). Operators reported that they had as many as about 1,600 miles and as few as 0.02 miles of pipeline in these areas. PHMSA, within the Department of Transportation, administers the national regulatory program to ensure the safe transportation of gas and hazardous liquids (e.g., oil, gasoline, and anhydrous ammonia) by pipeline. The agency attempts to ensure the safe operation of pipelines through regulation, national consensus standards, research, education (e.g., to prevent excavation-related damage), oversight of the industry through inspections, and enforcement when safety problems are found. In general, PHMSA retains full responsibility for inspecting and enforcing regulations on interstate pipelines but certifies states to perform these functions for intrastate pipelines. PHMSA employs about 165 staff in its pipeline safety program, about half of whom are pipeline inspectors who inspect gas and hazardous liquid pipelines under integrity management and other more traditional compliance programs. Nine PHMSA inspectors are currently devoted to the gas integrity management program. State pipeline agencies have about 325 inspectors, about 100 of which are currently able to perform integrity management inspections of intrastate gas transmission pipeline operators in 47 states. While the gas integrity management program is still being implemented, early indications suggest that it enhances public safety by supplementing existing safety standards with risk-based management principles. Prior to the integrity management program, there were, and still are, minimum safety standards that operators must meet for the design, construction, testing, inspection, operation, and maintenance of gas transmission pipelines. These standards apply equally to all pipelines and provide the public with a basic level of protection from pipeline failures. However, minimum standards do not require operators to identify and address risks that are specific to their pipelines, nor do they require operators to assess the integrity of their pipelines. While some operators have assessed the integrity of some of their pipelines, others have not. Consequently, some pipelines have operated for 40 or more years with no assessment. The gas integrity management requirements, finalized in 2004, go beyond the existing safety standards by requiring operators, regardless of size, to routinely assess pipelines in highly populated or frequented areas for specific threats, to take action to mitigate the threats, and to document management practices and decision-making processes. Representatives from the pipeline industry, safety advocate groups, state pipeline agencies, and operators we have contacted agree that the integrity management program enhances public safety. Some operators noted that, although the program’s requirements can be costly and time consuming to implement, the benefits to date are worth the costs. The primary benefit identified was the comprehensive knowledge the program requires all operators to have of their pipeline systems. For example, under integrity management, operators must gather and analyze information about their pipelines in highly populated or frequented areas to get a complete picture of the condition of those lines. This includes developing maps of the pipeline system and gathering information on corrosion protection, exposed pipeline, threats from excavation or other third-party damage, and the installation of automatic shut-off valves. Another benefit cited was improved communications within the company. Investigations of pipeline incidents have shown that, in some cases, an operator possessed information that could have prevented an incident but had not shared it with employees who needed it most. Integrity management requires operators to pull together pipeline data from various sources within the company to identify threats to the pipelines, leading to more interaction among different departments within pipeline companies. Finally, integrity management focuses operator resources on those areas where an incident could have the greatest impact. While industry and operator representatives have provided examples of the early benefits of integrity management, operators must report semiannually on performance measures that should quantitatively demonstrate the impact of the program over time. These measures include the total mileage of pipelines and the mileage of pipelines assessed in highly populated or frequented areas, as well as the number of repairs made and leaks, failures, and incidents identified in these areas. In the 2 years that operators have reported the results of integrity management, they have assessed about 6,700 miles of their 20,000 miles of pipelines located in highly populated or frequented areas, and they have completed 338 repairs that were immediately required and another 998 repairs that were less urgent. 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. For example, one operator told us that it had complied with all the minimum safety standards on its pipeline, and the pipeline appeared to be in good condition. The operator then assessed the condition of a segment of the pipeline under its integrity management program and found a serious problem, causing it to shut the line down for immediate repair. One of the most frequently cited concerns by the 41 operators we contacted was the uncertainty 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. Each operator must develop and document specific policies and procedures to demonstrate its commitment to compliance with and implementation of the integrity management requirements. In addition, an operator must document any decisions made related to integrity management. For example, an operator must document how it identified the threats to its pipeline in highly populated or frequented areas and who was involved in identifying the threats, their qualifications, and the data they used. While the operators we contacted 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. Moreover, they are concerned that they will not know if they have enough documentation until their program has been inspected. After conducting 13 inspections, PHMSA found that, while interstate operators are doing well in conducting assessments and making the identified repairs, they are having difficulty overall in the development and documentation of their management processes. Another concern raised by most of the operators is the requirement to reassess their pipelines at least every 7 years. I will discuss the 7-year reassessment requirement in more detail shortly. In response to our survey, most state officials indicated that the two most challenging areas for them as they begin implementing gas integrity management inspections are staffing and training. While most state agencies currently have at least two inspectors that can perform inspections of operators’ integrity management programs, some state pipeline officials responded that they do not have enough inspectors for the increased workload and/or their inspectors have not completed the training required by PHMSA. To ensure that inspectors have the technical expertise to conduct integrity management inspections, including evaluating operators’ processes and decisions, PHMSA requires inspectors to complete 4 classroom and 6 computer-based courses, totaling about 19 days of training. Three of the classroom courses are part of PHMSA’s core training for all inspectors and are generally offered annually. The fourth course—a new course that PHMSA established for integrity management—was made available to two inspectors from each state in 2005 and is now offered when there is sufficient demand. The computer- based courses were made available to the states starting in February 2005. While the state officials we spoke with agree that the training is necessary, they are concerned about the amount of time it takes to complete the required training and the limited availability of the classroom training. We will continue to follow up with state agencies about how these challenges will affect their oversight activities. I am pleased to report that in response to our 2002 recommendation, PHMSA has been working to improve its communication with states about their role in overseeing integrity management programs.