	Background

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. 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. 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. Operators must then repair or replace any defective pipelines. The act further provides that pipeline segments in highly populated or  frequented areas must be reassessed for safety risks at least every 7 years. 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. Early Indications Suggest that Gas Integrity Management Enhances Public Safety, but Operators and States Raise Some Concerns About Implementation

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. The primary benefit  identified was the comprehensive knowledge the program requires all  operators to have of their pipeline systems. Another concern raised by most of the operators is the  requirement to reassess their pipelines at least every 7 years. 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. Operators Favor a Risk- based, Rather than a One- Size-Fits-All, Reassessment Standard

As discussed earlier, as of December 2005, operators nationwide have  notified PHMSA of 338 problems that required immediate repair in the  6,700 miles in highly populated or frequented areas that they have  assessed—about one immediate repair required for every 20 miles of  pipeline assessed in highly populated or frequented areas. 1.) (The industry standard requires  that pipelines be reassessed at least every 5 years if all repairs are not  made. Some operators told us that the 7-year reassessment requirement is  conservative for pipelines that operate under lower stress. An industry concern about the 7-year reassessment requirement is that  operators will be required to conduct reassessments starting in 2010 while  they are still in the 10-year period (2003-2012) for conducting baseline  assessments. 2.) PHMSA Has Developed a Reasonable Framework for Its Enforcement Program

In 2004, we concluded that we could not assess the effectiveness of  PHMSA’s enforcement strategy because it had not incorporated key  features of effective program management—clear program goals, a well- defined strategy for achieving those goals, and performance measures that  link to the program goals. The strategy also links these efforts to goals to  reduce and prevent pipeline incidents and damage, in addition to providing  for periodic assessment of results. To  meet these goals, PHMSA has developed a multi-pronged strategy that is  directed at the pipeline industry and stakeholders (such as state  regulators), ensures that its processes make effective use of its resources. For example, PHMSA’s strategy calls for using risk-based enforcement to,  among other things, take enforcement actions that clearly reflect potential  risk and seriousness and deal severely with significant operator  noncompliance and repeat offenses. Third, the strategy, among other things, calls for improving PHMSA’s own  enforcement activities by developing comprehensive guidance tools,  training inspectors on their use, and effectively using state inspection  capabilities. We expect to provide additional insights into issues  involving state pipeline agency staffing and training and the 7-year  reassessment requirement when we report to this Subcommittee and  others this fall.
Why GAO Did This Study

About a dozen people are killed or injured in natural gas transmission pipeline incidents each year. In an effort to improve upon this safety record, the Pipeline Safety Improvement Act of 2002 requires that operators assess pipeline segments in about 20,000 miles of highly populated or frequented areas for safety risks, such as corrosion, welding defects, or incorrect operation. Half of these baseline assessments must be done by December 2007, and the remainder by December 2012. Operators must then repair or replace any defective pipelines, and reassess these pipeline segments for corrosion damage at least every 7 years. The Pipeline and Hazardous Materials Safety Administration (PHMSA) administers this program, called gas integrity management. This testimony is based on ongoing work for this Subcommittee and for other committees, as required by the 2002 act. The testimony provides preliminary results on the safety effects of (1) PHMSA's gas integrity management program and (2) the requirement that operators reassess their natural gas pipelines at least every 7 years. It also discusses how PHMSA has acted to strengthen its enforcement program in response to recommendations GAO made in 2004. GAO expects to issue two reports this fall that will address these and other topics. This testimony also discusses how PHMSA has strengthened its enforcement program in response to recommendations GAO made in 2004.

What GAO Found

Early indications suggest that the gas transmission pipeline integrity management program enhances public safety by supplementing existing safety standards with risk-based management principles. Operators have reported that they have assessed about 6,700 miles as of December 2005 and completed 338 repairs for problems they are required to address immediately. Operators told GAO that the primary benefit of the program is the comprehensive knowledge they must acquire about the condition of their pipelines. For some operators, the integrity management program has prompted such assessments for the first time. Operators raised concerns about (1) their uncertainty over the level of documentation that PHMSA requires and (2) whether their pipelines need to be reassessed at least every 7 years. The 7-year reassessment requirement is generally consistent with the industry consensus standard of at least every 10 years (higher operating pressure in relation to wall strength). The majority of transmission pipelines in the U.S. are estimated to be higher stress pipelines. However, most lower stress pipelines operators told GAO that the 7-year requirement is conservative for their pipelines because they found few problems requiring reassessments earlier than the 15 to 20 years under the industry standard. Operators GAO contacted said that periodic reassessments are beneficial for finding and preventing problems; but they favored reassessments on severity of risk rather than a one-size-fits-all standard. Operators did not expect that the existence of an "overlap period" from 2010 through 2012, when operators will be conducting baseline assessments and reassessments at the same time, would create problems in finding resources to conduct reassessments. PHMSA has developed a reasonable enforcement strategy framework that is responsive to GAO's earlier recommendations. PHMSA's strategy is aimed at reducing pipeline incidents and damage through direct enforcement and through prevention involving the pipeline industry and stakeholders (such as state regulators). Among other things, the strategy entails (1) using risk-based enforcement and dealing severely with significant noncompliance and repeat offenses, (2) increasing knowledge and accountability for results by clearly communicating expectations for operators' compliance, (3) developing comprehensive guidance tools and training inspectors on their use, and (4) effectively using state inspection capabilities.