On average, about 3 people have died and about 8 people have been injured each year over the last 10 years in natural gas transmission pipeline incidents. The number of incidents has increased from 77 in 1996 to 122 and 200 in 2004 and 2005, respectively, mostly reflecting more frequent occurrence of property damage. Much of this increase may be attributed to increases 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 that operators of gas transmission pipelines 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 defective pipelines. Risk-based assessments are 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 consistent with industry national consensus standards, operators must also reassess their pipeline segments for any safety risk at least every 5, 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 lie 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. 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. In addition, PHMSA is assisted by inspectors in 48 states, the District of Columbia, and Puerto Rico. 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 did assess the integrity of some of their pipelines, others did not. Some pipelines have been in operation 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, take action to mitigate the threats, and document management practices and decision-making processes. Representatives from the pipeline industry, safety advocate groups, 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 cost. 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 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 been shared 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 in 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 semi- annually 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 25 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 their commitment to compliance 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 did not disagree 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 11 inspections, PHMSA found that, while 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. As part of our assessment of the integrity management program, we are also examining how PHMSA and state pipeline agencies plan to oversee operator implementation of the program. To help federal and state inspectors prepare for and conduct integrity management inspections, PHMSA developed detailed inspection protocols tied to the integrity management regulations and a series of training courses covering the protocols and other relevant topics, such as corrosion and in-line inspection. Furthermore, in response to our 2002 recommendation, PHMSA has been working to improve its communication with states about their role in overseeing integrity management programs. For example, PHMSA’s efforts include (1) inviting state inspectors to attend federal inspections, (2) creating a website containing inspection information, and (3) providing a series of updates through the National Association of Pipeline Safety Representatives. I am pleased to report that preliminary results from an ongoing survey of state pipeline agencies (with more than half the states responding thus far) show that the majority of states that reported believe that the communication from PHMSA has been very or extremely useful in helping them understand their role and responsibilities in conducting integrity management inspections. Nationwide, pipeline operators reported to PHMSA that they have found, on average, about one problem requiring immediate repair or replacement for every 20 miles of pipeline assessed in highly populated or frequented areas. Operators we contacted recognize the benefits of reassessments; however, almost all would prefer following the industry national consensus standards that use safety risk, rather than a prescribed term, for determining when to reassess their pipelines. Most operators expect to be able to acquire the services and tools needed to conduct these reassessments including during an overlap period when they are starting to reassess pipeline segments while completing baseline assessments.