Three main types of pipelines carry hazardous liquid and natural gas from producing wells to end users (residences and businesses) and are managed by about 2,500 operators: Gathering pipelines collect hazardous liquid and natural gas from production areas and transport the products to processing facilities, which in turn refine and send the products to transmission pipelines. These pipelines tend to be located in rural areas but can also be located in urban areas. PHMSA estimates there are 200,000 miles of natural gas gathering pipelines and 30,000 to 40,000 miles of hazardous liquid gathering pipelines. Transmission pipelines carry hazardous liquid or natural gas, sometimes over hundreds of miles, to communities and large-volume users, such as factories. Transmission pipelines tend to have the largest diameters and operate at the highest pressures of any type of pipeline. PHMSA has estimated there are more than 400,000 miles of hazardous liquid and natural gas transmission pipelines across the United States. (See fig. 1.) Distribution pipelines then split off from transmission pipelines to transport natural gas to end users—residential, commercial, and industrial customers. There are no hazardous liquid distribution pipelines. PHMSA has estimated there are roughly 2 million miles of natural gas distribution pipelines, most of which are intrastate pipelines. PHMSA administers the national regulatory program to ensure the safe transportation of hazardous liquid and natural gas by pipeline, including developing safety requirements that all pipeline operators regulated by PHMSA must meet. In 2012, the agency’s budget was $201 million, which was used, in part, to employ over 200 staff in its pipeline safety program. About half of the pipeline safety program staff inspects hazardous liquid and gas pipelines for compliance with safety regulations. Besides PHMSA, over 300 state inspectors help oversee pipelines and ensure safety. State and federal officials may also investigate specific pipeline incidents to determine the reason for the pipeline failure and to take enforcement actions, when necessary. PHMSA enforces two general sets of pipeline safety requirements. The first are minimum safety standards that cover specifications for the design, construction, testing, inspection, operation, and maintenance of pipelines. The second set of safety requirements are part of a supplemental risk-based regulatory program termed “integrity management.” Under transmission pipeline integrity management programs, operators are required to systematically identify and mitigate risks to pipeline segments—discrete sections of the pipeline system separated by valves that can stop the flow of product—that are located in high-consequence areas where an incident would have greater consequences for public safety or the environment. To ensure operators comply with minimum safety standards and integrity management requirements, PHMSA conducts inspections in partnership with state pipeline safety agencies. Inspections may focus on specific pipeline segments or aspects of an operator’s safety program, or both. According to PHMSA, officials conduct an inspection for each operator at least once every 5 to 7 years, but may conduct additional inspections based on safety risk or at the discretion of PHMSA or state officials. PHMSA is authorized to take enforcement actions against operators, including issuing warning letters, notices of probable violation, notices of amendment, notices of proposed safety order, corrective action orders, and imposing civil penalties. Transporting hazardous liquids and natural gas by pipelines is associated with far fewer fatalities and injuries than other modes of transportation. From 2007 to 2011, there was an average of about 14 fatalities per year for all pipeline incidents reported to PHMSA, including an average of about 2 fatalities per year resulting from incidents on hazardous liquid and natural gas transmission pipelines. In comparison, in 2010, 3,675 fatalities resulted from incidents involving large trucks and 730 additional fatalities resulted from railroad incidents. Yet risks to pipelines exist, such as corrosion and third party excavation, which can damage a pipeline’s integrity and result in leaks and ruptures. A leak is a slow release of a product over a relatively small area. A rupture is a breach in the pipeline that may occur suddenly; the product may then ignite resulting in an explosion. According to pipeline operators we met with, of the two types of pipeline incidents, leaks are more common but generally cause less damage. Ruptures are relatively rare but can have much higher consequences because of the damage that can be caused by an associated explosion. According to PHMSA, industry, and state officials, responding to either a hazardous liquid or natural gas pipeline incident typically includes steps such as detecting that an incident has occurred, coordinating with emergency responders, and shutting down the affected pipeline segment. (See fig. 2.) Under PHMSA’s minimum safety standards, operators are required to have a plan that covers these steps for all of their pipeline segments and to follow that plan during an incident. Officials from PHMSA and state pipeline safety offices perform relatively minor roles during an incident, as they rely on operators and emergency responders to take actions to mitigate the consequences of such events. Following an incident, operators must report incidents that meet certain thresholds— including incidents that involve a fatality or injury, excessive property damage or product release, or an emergency shutdown—to the federal National Response Center, as well as conduct an investigation to identify the root cause and lessons learned. Federal and state authorities may also use their discretion to investigate some incidents, which can involve working with operators to determine the cause of the incident. If necessary, authorities will take steps to correct deficiencies in operator safety programs, including taking enforcement actions. While prior research shows that most of the fatalities and damage from an incident occur in the first few minutes following a pipeline rupture, operators can reduce some of the consequences by taking actions that include closing valves that are spaced along the pipeline to isolate segments. The amount of time it takes to close a valve depends upon the equipment installed on the pipeline. For example, valves with manual controls (referred to as “manual valves”) require a person to arrive on site and either turn a wheel crank or activate a push-button actuator. Valves that can be closed without a person located at the valve location (referred to as “automated valves”) include both remote-control valves, which can be closed via a command from a control room, and automatic-shutoff valves, which can close without human intervention based on sensor readings. (See fig. 3.) Automated valves generally take less time to close than manual valves. PHMSA’s minimum safety standards dictate the spacing of all valves, regardless of type of equipment installed to close them, while integrity management regulations require that transmission pipeline operators conduct a risk assessment for high- consequence areas that includes the consideration of automated valves. The ability of transmission pipeline operators to respond to incidents, such as leaks and ruptures, is affected by a number of variables—some of which are under operators’ control—resulting in variances in response time; for a given incident, that time can range from minutes to days. Several states and industry organizations have developed performance- based requirements for operators to meet in responding to incidents. PHMSA has some performance-based requirements, but its current performance goal related to incident response is not well defined. More precise performance measures and targets could lead to improved response times and less damage from incidents in some cases. However, PHMSA would need better data on incidents to determine the feasibility of such an approach. According to PHMSA officials, pipeline safety officials, and industry stakeholders and operators, multiple variables—some controllable by transmission pipeline operators—can influence the ability of operators to respond quickly to an incident. Ensuring a quick response is important because according to pipeline operators and industry stakeholders, reducing the amount of time it takes to respond to an incident can also reduce the amount of property and environmental damage stemming from an incident and, in some cases, the number of fatalities and injuries. For example, several natural gas pipeline operators noted that a faster incident response time could reduce the amount of property damage from secondary fires (after an initial pipeline rupture) by allowing fire departments to extinguish the fires sooner. In addition, hazardous liquid pipeline operators told us that a faster incident response time could result in lower costs for environmental remediation efforts and less product lost. We identified five variables that can influence incident response time and that are within an operator’s control: Leak detection capabilities. How quickly a leak is detected affects how soon an operator can initiate a response. Pipeline operators must perform a variety of leak detection activities to monitor their systems and identify leaks. These activities commonly include periodic external monitoring, such as aerial patrols of the pipeline, as well as continuous internal monitoring, such as measuring the intake and outtake volumes or pressure flows on the pipeline. In addition, pipeline operators must conduct public awareness programs for those living near pipeline facilities about how to recognize, respond to, and report pipeline emergencies; these programs can influence how quickly an operator becomes aware of an incident. Attempting to confirm an incident can also affect response time. Pipeline operators may prefer to have two sources of information to confirm an incident, such as data from a pipeline sensor and a visual confirmation, especially if shutting down the system is a likely response to the incident. Natural gas pipeline operators in particular generally seek to confirm an incident before a shutdown, as shutdowns interrupt the gas flow and can cut off service to their customers. Location of qualified operator response personnel. The proximity of the operator’s response personnel to a facility or shutoff valve can affect the response time. Response personnel who have a greater distance to travel to the facility or valve site can take longer to establish an incident command center or to close manual valves. Along with proximity, incident response time depends on whether qualified operator response personnel—those who are trained and are authorized to take necessary action, such as closing manual valves— are dispatched. Type of valves. The type of valve an operator has installed on a pipeline segment can affect how quickly the segment can be isolated.