The United States has a network of about 300,000 miles of gas transmission pipelines that are owned and operated by approximately 900 operators. These pipelines, which are primarily interstate, typically move gas products over long distances from sources to communities, and tend to operate at the highest pressures and have the largest diameters of any Gas transmission pipelines are critical because they type of pipeline.transport nearly all of the natural gas used in the United States, which fuels about a quarter of the nation’s energy needs. Pipelines do not experience many of the safety threats faced by other forms of freight transportation because they are mostly underground. However, they are subject to problems that can occur over time (such as leaks and ruptures resulting from corrosion) or are independent of time (such as damage from excavation, land movement, or incorrect operation). PHMSA administers the national regulatory program to ensure the safe transportation of natural gas and hazardous liquids (e.g., petroleum or anhydrous ammonia) by pipeline, including developing safety requirements that all pipeline operators regulated by PHMSA must meet. In fiscal year 2012, the agency’s total budget was $201 million, about half of which is for pipeline safety activities. PHMSA’s Office of Pipeline Safety employs over 200 staff, with about 135 of those staff involved in inspections and enforcement. In addition, over 300 state inspectors help oversee pipelines and ensure safety. Pipeline operators are subject to PHMSA’s minimum safety standards for the design, construction, testing, inspection, operation, and maintenance of gas transmission pipelines. However, this approach does not systematically account for differences in the kinds of threats and the degrees of risk that individual pipelines face. For example, pipelines located in the Pacific Northwest are more susceptible to damage from geologic hazards, such as land movement, than pipelines in some other areas of the country. Federal efforts to incorporate risk-based concepts into pipeline management began in earnest in the mid-1990s. For example, the Accountable Pipeline Safety and Partnership Act of 1996 required the Department of Transportation to establish risk management The purpose of this effort was “to demonstrate, demonstration projects. through the voluntary participation by owners and operators of gas pipeline facilities and hazardous liquid facilities, the application of risk management; and to evaluate the safety and cost-effectiveness of the program.”approach to safety: the integrity management program. Integrity management helps ensure safety by, among other things, using information to identify and assess risks and prioritizing risks so that resources may be allocated to address higher risks first. The integrity management program requires operators to perform a number of activities, such as identifying high consequence areas and pipelines These projects helped PHMSA establish a more risk-based within those areas, as well as identifying the threats facing those pipelines. PHMSA first implemented integrity management requirements for hazardous liquid pipeline operators with 500 or more miles of pipelines in December 2000, followed by hazardous liquid pipeline operators with less than 500 miles in January 2002. The Pipeline Safety Improvement Act of 2002 extended the integrity management program to gas transmission pipelines, which include about 20,000 miles of pipeline segments located in high consequence areas.subject to PHMSA’s integrity management program, operators must still meet the minimum safety standards noted above. As part of the integrity management program, operators are required to assess the integrity of their pipelines within high consequence areas on a regular basis using approved methods. Specifically, gas transmission pipeline operators were required to complete a baseline assessment on pipeline segments within high consequence areas by December 17, 2012. According to the 2002 act, operators are then required to complete reassessments of these pipelines at least every 7 years. Gas transmission pipeline operators completed most baseline assessments by December 17, 2012, and reassessments are currently under way. From 2004 through December 2011 (the latest data available), baseline assessments were conducted on over 23,450 miles of gas transmission pipeline in high consequence areas. Over 4,470 miles of gas transmission pipeline in high consequence areas—or about 20 percent of the pipeline miles that had a completed baseline assessment between 2004 and 2011—were reported as reassessed between 2008 and 2011 (see fig. 1). Among other things, PHMSA’s integrity management regulations required operators to (1) prioritize their baseline assessments to assess riskier pipelines first and (2) complete baseline assessments of these riskier pipelines by December 2007, and all pipelines within high consequence areas by December 2012. As a result, a small spike in the mileage assessed occurred in 2007. Under PHMSA’s regulations, gas transmission pipeline operators may use any of three primary approaches to conduct assessments: In-line inspection: In-line inspection involves running a specialized tool—often known as a smart pig—through the pipeline to detect and record anomalies, such as metal loss and damage (see fig. 2). In-line inspection allows operators to determine the nature of any problems without either shutting down the pipeline for extended periods or potentially damaging the pipeline. In-line inspection devices can be run only from specific launch and retrieval points, which may extend beyond high consequence areas. Operators using in-line inspection will often gather information along the entire distance between launching and retrieval locations to gain additional safety information. Based on PHMSA’s data, the majority of pipeline miles assessed in 2011 (88 percent) were done using in-line inspection. Direct assessment: Direct assessment is an aboveground assessment method used to identify problem areas on a pipeline. The process includes gathering data on potential risks facing the pipeline, analyzing those data to identify potential problem locations, and then excavating and directly examining those locations. PHMSA regulations require that at least two or more aboveground detection instruments, such as a close interval survey,direct assessment. be used to constitute a Hydrostatic testing: Hydrostatic testing entails sealing off a portion of the pipeline, removing the gas product and replacing it with water, and increasing the pressure of the water above the rated strength of the pipeline to test its integrity. If the pipeline leaks or ruptures, the pipeline is excavated to determine the cause of the failure. Operators must shut down pipelines to perform hydrostatic testing. Also, this assessment method can weaken the pipeline due to the high pressures involved, making it more susceptible to failure later. Finally, operators must be able to dispose of large quantities of waste water in an environmentally responsible manner. According to the operators we spoke with, the costs associated with performing each of these assessment methods varies greatly. For example, operators told us that the estimated average cost for conducting a direct assessment ranges from $5,000 per mile to $500,000 per mile. The costs vary due to a number of factors, such as the amount of pipeline mileage to be assessed and the number of digs that must be performed after completing an assessment to confirm the findings. PHMSA’s regulations promulgated pursuant to the Pipeline Safety Improvement Act of 2002 require gas transmission pipeline operators to reassess their pipelines for all safety risks—such as corrosion, excavation, land movement, or incorrect operation—at regular intervals based on industry consensus standards. But the regulations limit the 7- year reassessment requirement in the 2002 act to corrosion damage only because corrosion is the most frequent cause of failures that can occur over time. The industry consensus standards adopted in PHMSA’s regulations require that gas transmission pipeline operators reassess their pipelines for all safety risks at least every 10, 15, or 20 years, depending primarily on the condition and operating pressure of the pipelines, with pressure measured as a percentage of specified minimum If an operator elects to establish a reassessment interval yield strength.for all safety risks based on the industry consensus standards, it must—in order to comply with the 2002 act—perform what is called a “confirmatory direct assessment” by at least the seventh year to assess corrosion damage, and then conduct the reassessment for all safety risks at the interval the operator established. Alternatively, an operator can elect to perform a reassessment for all safety risks (including corrosion damage) at least every 7 years in order to comply with both the 2002 act and PHMSA’s regulations. Figure 3 provides some examples in which an operator can meet its reassessment requirements, either through performing (1) a confirmatory direct assessment at year 7 and a reassessment for all safety risks at a later year that comports with the industry consensus standards, or (2) a reassessment for all safety risks every 7 years. The 7-year reassessment requirement in the Pipeline Safety Improvement Act of 2002 as well as the reassessment intervals noted in PHMSA’s regulations and the industry consensus standards are maximum reassessment intervals: they represent the maximum number of years between reassessments. If pipeline conditions and risks dictate more frequent reassessments, then pipeline operators must do so to comply with PHMSA’s regulations. In addition, between reassessments, operators must—regardless of whether their pipeline mileage is located in a high consequence area—patrol their pipelines, survey for leakage, maintain valves, ensure that corrosion-preventing cathodic protection is working properly, and take measures to prevent excavation damage. In general, PHMSA has full responsibility for inspecting interstate pipelines and enforcing regulations pertaining to them, although some states are designated as “interstate agents” to assist PHMSA. PHMSA also has arrangements with the 48 contiguous states, the District of Columbia, and Puerto Rico to assist with overseeing intrastate pipelines. State pipeline safety offices are allowed to issue regulations supplementing or extending federal regulations for intrastate pipelines, but these state regulations must be at least as stringent as the minimum federal regulations. PHMSA’s baseline assessment and reassessment data from 2004 to 2011 show that pipeline operators have identified and are making critical repairs in high consequence areas, specifically for conditions requiring repairs immediately or within one year. For immediate conditions, operators must make a repair as soon as possible and reduce pipeline operating pressure or shut down the pipeline until the repair is completed.