PIPELINE SAFETY

Better Data and Guidance 

Could Improve Operators’ 

Responses to Incidents

Statement of Susan A. Fleming, Director 

Physical Infrastructure Issues

Testimony

Before the Committee on Commerce, 

Science, and Transportation, 

U.S. Senate

For Release on Delivery 

Expected at 12:00 p.m. EST

Monday, January 28, 2013

GAO-13-284T

United States Government Accountability Office

GAO
Page 1 GAO-13-284T Pipeline Safety 

United States Government Accountability Office

Washington, DC 20548 

Chairman Rockefeller and Members of the Committee: 

Thank you for the opportunity to participate in this hearing on pipeline 

safety. As you know, pipelines are a relatively safe means of transporting 

natural gas and hazardous liquids; however, catastrophic incidents can 

and do occur.1

 We are here today because such an incident occurred on 

December 11, 2012, near Sissonville, West Virginia, when a rupture of a 

natural gas transmission pipeline destroyed or damaged 9 homes and 

badly damaged a section of Interstate 77. Large-diameter transmission 

pipelines such as these that carry products over long distances from 

processing facilities to communities and large-volume users make up 

more than 400,000 miles of the 2.5 million mile natural gas and 

hazardous liquid pipeline network in the United States.2

 The Department 

of Transportation’s (DOT) Pipeline and Hazardous Materials Safety 

Administration (PHMSA), working in conjunction with state pipeline safety 

offices, oversees this network, which transports about 65 percent of the 

energy we consume. 

The best way to ensure the safety of pipelines, and their surrounding 

communities, is to minimize the possibility of an incident occurring. 

PHMSA’s regulations require pipeline operators to take appropriate 

preventive measures such as corrosion control and periodic assessments 

of pipeline integrity. To mitigate the consequences if an incident occurs, 

operators are also required to develop leak detection and emergency 

response plans. One mitigation measure operators can take is to install 

automated valves that, in the event of an incident, close automatically or 

can be closed remotely by operators in a control room.3

 Such valves have 

been the topic of several National Transportation Safety Board (NTSB) 

 

1

In its regulations, PHMSA refers to the release of natural gas from a pipeline as an 

“incident” (49 C.F.R. § 191.3) and a spill from a hazardous liquid pipeline as an “accident.” 

(49 C.F.R. §195.50). For simplicity, this statement refers to both as “incidents.” 

2

This statement uses the term “transmission pipeline” to refer to both onshore hazardous 

liquid and natural gas pipelines carrying product over long distances to users. 

3

For the purposes of this statement, the term “install an automated valve” refers to any 

actions that allow the operator to remotely or automatically close a valve. Such actions do 

not necessarily mean an operator is installing a completely new valve. For example, 

operators may install an actuator and communications at an existing valve location. 

 
 

Page 2 GAO-13-284T Pipeline Safety 

recommendations since 1971 and a PHMSA report issued in October 

2012.4

As mandated in the Pipeline Safety, Regulatory Certainty, and Job 

Creation Act of 2011, we issued a January 2013 report on the ability of 

transmission pipeline operators to respond to a hazardous liquid or 

natural gas release from an existing pipeline segment.5 My statement 

today is based on this report and addresses (1) variables that influence 

the ability of transmission pipeline operators to respond to incidents and 

(2) opportunities to improve these operators’ responses to incidents. My 

statement also provides information from two other recent GAO reports 

on pipeline safety (see app. I). For our January 2013 report, we examined 

incident data, conducted a literature review, and interviewed selected 

operators, industry stakeholders, state pipeline safety offices, and 

PHMSA officials. Our work on each pipeline safety report was conducted 

in accordance with generally accepted government auditing standards. 

Those standards require that we plan and perform the audit to obtain 

sufficient, appropriate evidence to provide a reasonable basis for our 

findings and conclusions based on our audit objectives. We believe that 

the evidence obtained provides a reasonable basis for our findings and 

conclusions based on our audit objectives.

Numerous variables—some of which are under operators’ control—

influence the ability of transmission pipeline operators to respond to 

incidents. For example, the location of response personnel and the use of 

manual or automated valves can affect the amount of time it takes for 

operators to respond to incidents. However, because the advantages and 

disadvantages of installing an automated valve are closely related to the 

specifics of the valve’s location, it is appropriate that operators decide 

whether to install automated valves on a case-by-case basis. Several 

 

4

Oak Ridge National Laboratory, Studies for the Requirements of Automatic and Remotely 

Controlled Shutoff Valves on Hazardous Liquids and Natural Gas Pipelines with Respect to 

Public and Environmental Safety, ORNL/TM-2012/411 (Oct. 31, 2012). The study was 

conducted pursuant to the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 

2011, which directed the Secretary of Transportation to consider additional regulations 

requiring the use of automated valves where economically, technically, and operationally 

feasible on new transmission facilities. Pub. L. No. 112-90, § 4, 125 Stat. 1904, 1906 (2012). 

5

GAO, Pipeline Safety: Better Data and Guidance Needed to Improve Pipeline Operator 

Incident Response, GAO-13-168 (Washington, D.C.: Jan. 23, 2013).

Summary
 

Page 3 GAO-13-284T Pipeline Safety 

operators we spoke with have developed approaches to evaluate the 

advantages and disadvantages of installing automated valves, such as 

using spill-modeling software to estimate the potential amount of product 

released and extent of damage that would occur in the event of an 

incident.

One method PHMSA could use to improve operator response to incidents 

is to develop a performance-based approach for incident response times. 

While defining performance measures and targets for incident response 

can be challenging, PHMSA could move toward a performance-based 

approach by evaluating nationwide data to determine response times for 

different types of pipeline (based on location, operating pressure, and 

pipeline diameter, among other factors). First, though, PHMSA must 

improve the data it collects on incident response times. These data are 

not reliable because operators are not required to fill out certain timerelated fields in the reporting form and because operators told us they 

interpret these data fields in different ways. Furthermore, while PHMSA 

conducts a variety of information-sharing activities, the agency does not 

formally collect or share evaluation approaches used by operators to 

decide whether to install automated valves, and not all operators we 

spoke with were aware of existing PHMSA guidance designed to assist 

operators in making these decisions. We recommended that PHMSA 

should: (1) improve incident response data and use those data to explore 

the feasibility of developing a performance-based approach for improving 

operators’ responses to pipeline incidents and (2) assist operators in 

deciding whether to install automated valves by formally collecting and 

sharing evaluation approaches and ensuring operators are aware of 

existing guidance. PHMSA agreed to consider these recommendations.

Three main types of pipelines—gathering, transmission, and 

distribution—carry hazardous liquid and natural gas from producing wells 

to end users (residences and businesses) and are managed by about 

3,000 operators. Transmission pipelines carry these products, 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.

PHMSA administers two general sets of pipeline safety requirements and 

works with state pipeline safety offices to inspect pipelines and enforce 

the requirements. The first set of requirements is minimum safety 

Background
 

Page 4 GAO-13-284T Pipeline Safety 

standards that cover specifications for the design, construction, testing, 

inspection, operation, and maintenance of pipelines. The second set is 

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 that are located in highly populated or 

environmentally sensitive areas (called “high-consequence areas”).6

According to PHMSA, industry, and state officials, responding to either a 

hazardous liquid or natural gas pipeline incident typically includes 

detecting that an incident has occurred, coordinating with emergency 

responders, and shutting down the affected pipeline segment. 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. 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.7

Operators must also conduct an investigation to identify the root cause 

and lessons learned, and report to PHMSA. Federal and state authorities 

may use their discretion to investigate some incidents, which can involve 

working with operators to determine the cause of the incident.8

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 

 

6

“High-consequence areas” are defined differently for hazardous liquid and natural gas. 

For natural gas, such areas typically include highly populated or frequented areas, such 

as parks. For hazardous liquid, high-consequence areas include highly populated areas, 

other populated areas, navigable waterways, and areas unusually sensitive to 

environmental damage. 

7

The National Response Center, managed by the United States Coast Guard, is the sole 

federal point of contact for reporting oil and chemical spills. 

8

PHMSA may conduct an incident investigation in instances when an NTSB investigation 

is also under way. In such cases, PHMSA does not determine the cause of the incident; 

rather its review is to determine regulatory compliance.
 

Page 5 GAO-13-284T Pipeline Safety 

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 at the valve’s location (referred to as 

“automated valves”) include 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.9

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,10 while integrity 

management regulations require that transmission pipeline operators 

conduct a risk assessment for pipelines in high-consequence areas that 

includes the consideration of automated valves.

Multiple variables—some controllable by transmission pipeline 

operators—can influence the ability of operators to respond quickly to an 

incident, according to PHMSA officials, pipeline safety officials, and 

industry stakeholders and operators. 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 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 are within an operator’s control, and four other 

variables that influence a pipeline operator’s ability to respond to an 

incident but are beyond an operator’s control. The effect a given variable 

 

9

Hazardous liquid regulations refer to emergency flow restriction devices, which include 

remote-control valves and “check” valves that automatically prevent product from flowing 

in a specific direction. See 49 C.F.R. § 195.452(i)(4). We refer to all of these valves as 

automated valves.

1049 C.F.R. §§ 192.179, 195.260.

Incident Response 

Time Depends on 

Multiple Variables, 

Including the Use of 

Automated Valves
 

Page 6 GAO-13-284T Pipeline Safety 

has on a particular incident response will vary according to the specifics 

of the situation. The five variables within an operator’s control are:

• leak detection capabilities,

• location of qualified operator response personnel,

• type of valve,

• control room management, and

• relationships with local first responders.

The four factors beyond an operator’s control are:

• type of release,

• time of day,

• weather conditions, and

• other operators’ pipelines in the same area.

(See table 1 for further detail.) Appendix II provides several examples of 

response time in past incidents; response time varied from several 

minutes to days depending on the presence and interaction of the 

variables just mentioned.
 

Page 7 GAO-13-284T Pipeline Safety 

Table 1: Variables Influencing Pipeline Operator Incident Response Times

Variables within an operator’s control Variables beyond an operator’s control

• Leak detection capabilities. Pipeline operators perform a 

variety of leak detection activities to monitor their systems 

and identify leaks, including 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 in the pipeline.

• Type of release (leak vs. rupture). Leaks are generally a slow 

release of product over a small area, which can go undetected 

for long periods. Once a leak is detected, it can take additional 

time to confirm the exact location. Ruptures, which usually 

produce more significant changes in the external or internal 

conditions of the pipeline, are typically easier to detect and 

locate.

• Time of day. The operator’s response personnel may be 

delayed in reaching facilities in urban or suburban areas during 

peak traffic times. Conversely, if an incident occurs during the 

evening or on a weekend, the operator’s response personnel 

could be able to reach the facility more quickly, because of 

lighter traffic.

• Weather conditions. Weather—such as storms, winter 

conditions, and wind—can affect how quickly an operator can 

detect and respond to pipeline incidents.

• Other operators’ pipelines in the same area. If two or more 

operators own pipeline in a shared right of way determining 

whose system is affected can increase incident response time.

• Location of qualified operator response personnel. 

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.

• Type of valves. Automated valves, which can be closed 

automatically or remotely, can shorten incident response 

time compared to manual valves, which require that 

personnel travel to the valve site and turn a wheel crank or 

activate a push-button actuator to close the valve.

• Control room management. Clear operating policies and 

shutdown protocols for control room personnel can 

influence response time to incidents. For example, incident 

response time might be reduced if control room personnel 

have the authority to shut down a pipeline or facility if a 

leak is suspected, and are encouraged to do so.

• Relationships with local first responders. Operators that 

have already established effective communications with 

local first responders—such as fire and police 

departments—may respond more quickly during 

emergencies.

Source: GAO analysis of information from PHMSA officials, pipeline safety officials, and industry stakeholders and operators.

As noted, one variable that influences operators’ response times to 

incidents is the type of valve installed on the pipeline. Research and 

industry stakeholders indicate that the primary advantage of installing 

automated valves—as opposed to other safety measures—is related to 

the time it takes to respond to an incident. Although automated valves 

cannot mitigate the fatalities, injuries, and damage that occur in an initial 

blast, quickly isolating the pipeline segment through automated valves 

can reduce subsequent damage by reducing the amount of hazardous 

liquid and natural gas released.

Research and industry stakeholders also identified two disadvantages 

operators should consider when determining whether to install automated 

valves related to potential accidental closures and the monetary costs of 

purchasing and installing the equipment. Specifically, automated valves 

can lead to accidental closures, which can have severe, unintended 

consequences, including loss of service to residences and businesses. In 
 

Page 8 GAO-13-284T Pipeline Safety 

addition, according to operators, vendors and contractors, the monetary 

costs of installing automated valves can range from tens of thousands to 

a million dollars per valve,11

Research and industry stakeholders also indicate the importance of 

determining whether to install valves on a case-by-case basis because 

the advantages and disadvantages can vary considerably based on 

factors specific to a unique valve location. These sources indicated that 

the location of the valve, existing shutdown capabilities, proximity of 

personnel to the valve’s location, the likelihood of an ignition, type of 

product being transported, operating pressure, topography, and pipeline 

diameter, among other factors, all play a role in determining the extent to 

which an automated valve would be advantageous.

which may be significant expenditures for 

some pipeline operators. According to operators and other industry 

stakeholders, considering monetary costs is important when making 

decisions to install automated valves because resources spent for this 

purpose can take away from other pipeline safety efforts. Specifically, 

operators and industry stakeholders told us they often would rather focus 

their resources on incident prevention to minimize the risk of an incident 

instead of focusing resources on incident response. PHMSA officials 

stated that they generally support the idea that pipeline operators be 

given some flexibility to target spending where the operator believes it will 

have the most safety benefit.

Operators we met with are using a variety of methods for determining 

whether to install automated valves that consider—on a case-by-case 

basis—whether these valves will improve response time, the potential for 

accidental closure, and monetary costs. For example, two natural gas 

pipeline operators told us that they applied a decision tree analysis to all 

pipeline segments in highly populated and frequented areas. They used 

the decision tree to guide a variety of yes-or-no questions on whether 

installing an automated valve would improve response time to less than 

an hour and provide advantages for locations where people might have 

difficulty evacuating quickly in the event of a pipeline incident. Other 

hazardous liquid pipeline operators said they used computer-based spill 

modeling to determine whether the amount of product release would be 

significantly reduced by installing an automated valve.

 

11The cost of installing an automated valve ranges depending on the location and size of 

the pipeline and the type of equipment being installed, among other things.
 

Page 9 GAO-13-284T Pipeline Safety 

In our report, we note that PHMSA has not developed a performancebased framework for incident response times, although some 

organizations in the pipeline industry have done so.12 We and others have 

recommended that the federal government move toward performancebased regulatory approaches to allow those being regulated to determine 

the most appropriate way to achieve desired, measurable outcomes.13

According to our past work, such a framework should include: (1) national 

goals, (2) performance measures that are linked to those national goals, 

and (3) appropriate performance targets that promote accountability and 

allow organizations to track their progress toward goals. While PHMSA 

has established a national goal for incident response times, it has not 

linked performance measures or targets to this goal. Specifically, PHMSA 

directs operators to respond to certain incidents—emergencies that 

require an immediate response14

 

12For example, according to the National Association of Pipeline Safety Representatives, 

several state pipeline safety offices have initiatives that require natural gas pipeline 

operators to respond within a specified time frame to reports of pipeline leaks. In addition, 

members of the Interstate Natural Gas Association of America have committed to 

achieving a 1-hour incident response time for large diameter (greater than 12 inches) 

natural gas pipelines in highly populated areas. To meet this goal, operators are planning 

changes to their systems, such as relocating response personnel and automating over 

1,800 valves throughout the United States.

—in a “prompt and effective” manner, 

but neither PHMSA’s regulations nor its guidance describe ways to 

measure progress toward meeting this goal. Without a performance 

measure and target for a prompt and effective incident response, PHMSA 

cannot quantitatively determine whether an operator meets this goal and 

track their performance over time. PHMSA officials told us that because 

pipeline incidents often have unique characteristics, developing a 

performance measure and associated target for incident response time 

13In addition, NTSB has recommended that the Department of Transportation conduct an 

audit to assess the effectiveness of PHMSA’s oversight of performance-based safety 

programs. See NTSB, Pipeline Accident Report: Pacific Gas and Electric Company 

Natural Gas Transmission Pipeline Rupture and Fire, San Bruno, California, September 9, 

2010, NTSB/PAR-11/01 (Washington, D.C: Aug. 30, 2011). In response to the NTSB 

recommendation, the Department of Transportation is currently conducting an audit, which 

it expects to issue in early 2013, that will evaluate the effectiveness of PHMSA’s 

inspection and oversight of pipeline operators’ integrity management programs, including 

expanding the use of meaningful metrics and setting goals for pipeline operators and 

tracking performance against those goals.

14Emergencies include natural gas detected inside or near a building, accidental release 

of hazardous liquid or carbon dioxide from a pipeline facility, fire or explosion occurring 

near or directly involving a pipeline facility, operational failure causing a hazardous 

condition, or natural disaster affecting pipeline facilities.

Performance-Based 

Approach Offers 

Opportunity to 

Measure and Improve 

Incident Response, 

but Better Data and 

Guidance Are Needed
 

Page 10 GAO-13-284T Pipeline Safety 

would be difficult. In particular, it would be challenging to establish a 

performance measure using incident response time in a way that would 

always lead to the desired outcome of a prompt and effective response. 

In addition, officials stated it would be difficult to identify a single response 

time target for all incidents, as pipeline operators likely should respond to 

some incidents more quickly than others.

Defining performance measures and targets for incident response can be 

challenging, but one possible way for PHMSA to move toward a more 

quantifiable, performance-based approach would be to develop strategies 

to improve incident response based on nationwide data. For example, 

performing an analysis of nationwide incident data—similar to PHMSA’s 

current analyses of fatality and injury data—could help PHMSA determine 

response times for different types of pipelines (based on characteristics 

such as location, operating pressure, and diameter); identify trends; and 

develop strategies to improve incident response. However, we found that 

PHMSA does not have the reliable nationwide data on incident response 

time data it would need to conduct such analyses. Specifically, the 

response time data PHMSA currently collects are unreliable for two 

reasons: (1) operators are not required to fill out certain time-related fields 

in the PHMSA incident-reporting form and (2) when operators do provide 

these data, they are interpreting the intended content of the data fields in 

different ways. Our report recommended that PHMSA improve incident 

response data and use these data to evaluate whether to implement a 

performance-based framework for incident response times. PHMSA 

agreed to consider this recommendation.

We also found that PHMSA needs to do a better job of sharing 

information on ways operators can make decisions to install automated 

valves. For example, many of the operators we spoke with were unaware 

of existing PHMSA enforcement and inspection guidance that could be 

useful for operators in determining whether to install automated valves on 

transmission pipelines. In addition, while PHMSA inspectors see 

examples of how operators make decisions to install automated valves 

during integrity management inspections, they do not formally collect this 

information or share it with other operators. Given the variety of riskbased methods for making decisions about automated valves across the 

operators we spoke with, we believe that both operators and inspectors 

would benefit from exposure to some of the methods used by other 

operators to make decisions on whether to install automated valves. Our 

report recommended that PHMSA share guidance and information on 

operators’ decision-making approaches to assist operators with these 

determinations. PHMSA also agreed to consider this recommendation.
 

Page 11 GAO-13-284T Pipeline Safety 

Chairman Rockefeller this concludes my prepared remarks. I am happy 

to respond to any questions that you or other Members of the Committee 

may have at this time. 

For questions about this statement, please contact Susan Fleming, 

Director, Physical Infrastructure, at (202) 512-3824 or flemings@gao.gov. 

In addition, contact points for our Offices of Congressional Relations and 

Public Affairs may be found on the last page of this statement. Individuals 

who made key contributions to this statement include Sara Vermillion 

(Assistant Director), Sarah Arnett, Melissa Bodeau, Russ Burnett, 

Matthew Cook, Colin Fallon, Robert Heilman, David Hooper, and 

Josh Ormond. 

GAO Contact and 

Staff 

Acknowledgments 
Appendix I: Summary of Recent GAO Reports 

on Gathering Pipelines and Low-stress 

Transmission Pipelines 

Page 12 GAO-13-284T Pipeline Safety 

GAO recently issued two reports related to the safety of certain types of 

pipelines. The first, GAO-12-388, reported on the safety of gathering 

pipelines, which currently are largely unregulated by the federal 

government. The second, GAO-12-389R, reported on the potential safety 

effects of applying less prescriptive requirements, currently levied on 

distribution pipelines, to low-stress natural gas transmission pipelines. 

Further detail on each report is provided below. For the full report text, go 

to www.gao.gov. 

GAO-12-388: Collecting Data and Sharing Information on Federally 

Unregulated Gathering Pipelines Could Help Enhance Safety

Included in the nation’s pipeline network are an estimated 200,000 or 

more miles of onshore gathering pipelines, which transport products to 

processing facilities and larger pipelines. Many of these pipelines have 

not been subject to federal regulation because they are considered less 

risky due to their generally rural location and low operating pressures. For 

example, out of the more than 200,000 estimated miles of natural gas 

gathering pipelines, the Pipeline and Hazardous Materials Safety 

Administration (PHMSA) regulates roughly 20,000 miles. Similarly, of the 

30,000 to 40,000 estimated miles of hazardous liquid gathering pipelines, 

PHMSA regulates about 4,000 miles.1

While the safety risks of onshore gathering pipelines that are not 

regulated by PHMSA are generally considered to be lower than for other 

types of pipelines, PHMSA does not collect comprehensive data to 

identify the safety risks of unregulated gathering pipelines. Without data 

on potential risk factors—such as information on construction quality, 

maintenance practices, location, and pipeline integrity—pipeline safety 

officials are unable to assess and manage safety risks associated with 

gathering pipelines. Further, some types of changes in pipeline 

operational environments could also increase safety risks for federally 

unregulated gathering pipelines. Specifically, land-use changes are 

resulting in development encroaching on existing pipelines, and the 

increased extraction of oil and natural gas from shale deposits is resulting 

in the construction of new gathering pipelines, some of which are larger in 

diameter and operate at higher pressure than older pipelines. As a result, 

PHMSA is considering collecting data on federally unregulated gathering 

 

1

According to PHMSA officials, Alaska, California, Louisiana, and Oklahoma have the 

majority of federally unregulated gathering pipeline mileage in the United States.

Appendix I: Summary of Recent GAO Reports 

on Gathering Pipelines and Low-stress 

Transmission Pipelines
Appendix I: Summary of Recent GAO Reports 

on Gathering Pipelines and Low-stress 

Transmission Pipelines 

Page 13 GAO-13-284T Pipeline Safety 

pipelines. However, the agency’s plans are preliminary, and the extent to 

which PHMSA will collect data sufficient to evaluate the potential safety 

risks associated with these pipelines is uncertain.

In addition, we found that the amount of sharing of information to ensure 

the safety of federally unregulated pipelines among state and federal 

pipeline safety agencies appeared limited. For example, some state and 

PHMSA officials we interviewed had limited awareness of safety practices 

used by other states. Increased communication and information sharing 

about pipeline safety practices could boost the use of such practices for 

unregulated pipelines.

We recommended that PHMSA should collect data on federally 

unregulated onshore hazardous liquid and gas gathering pipelines, 

subsequent to an analysis of the benefits and industry burdens 

associated with such data collection. Data collected should be 

comparable to what PHMSA collects annually from operators of regulated 

gathering pipelines (e.g., fatalities, injuries, property damage, location, 

mileage, size, operating pressure, maintenance history, and the causes of 

incidents and consequences). Also, we recommended that PHMSA 

establish an online clearinghouse or other resource for states to share 

information on practices that can help ensure the safety of federally 

unregulated onshore hazardous liquid and gas gathering pipelines. This 

resource could include updates on related PHMSA and industry 

initiatives, guidance, related PHMSA rulemakings, and other information 

collected or shared by states. PHMSA concurred with our 

recommendations and is taking steps to implement them.

GAO-12-389R: Safety Effects of Less Prescriptive Requirements for 

Low-Stress Natural Gas Transmission Pipelines Are Uncertain

Gas transmission pipelines typically move natural gas across state lines 

and over long distances, from sources to communities. Transmission 

pipelines can generally operate at pressures up to 72 percent of specified 

minimum yield strength (SMYS).2

 

2

Pipelines will begin to deform at a certain level of operating pressure. As a result, 

pipelines operate at a percentage of the level of pressure that will cause the pipeline to 

deform, known as SMYS. The SMYS depends on the type of metal and is an indicator of 

when the metal in the pipe starts to yield, deforming in a way that does not return to its 

original shape. By definition, transmission pipelines operate at or above 20 percent of 

SMYS (49 CFR § 192.3). Some transmission pipelines operate under special permits that 

allow different maximum operating pressure that could exceed 72 percent of SMYS. 

By contrast, local distribution pipelines 
Appendix I: Summary of Recent GAO Reports 

on Gathering Pipelines and Low-stress 

Transmission Pipelines 

Page 14 GAO-13-284T Pipeline Safety 

generally operate within state boundaries to receive gas from 

transmission pipelines and distribute it to commercial and residential end 

users. Distribution pipelines typically operate well below 20 percent of 

SMYS. Connecting the long-distance transmission pipelines to the local 

distribution pipelines are lower stress transmission pipelines that may 

transport natural gas for several miles at pressures between 20 and 30 

percent of SMYS.

Applying PHMSA’s distribution integrity management requirements to 

low-stress transmission pipelines would result in less prescriptive safety 

requirements for these pipelines. Overall, requirements for distribution 

pipelines are less prescriptive than requirements for transmission 

pipelines in part because the former operate at lower pressure and pose 

lower risks in general than the latter. For example, the integrity 

management regulations for transmission pipelines allow three types of 

in-depth physical inspection. In contrast, distribution pipeline operators 

can customize their integrity management programs to the complexity of 

their systems, including using a broader range of methods for physical 

inspection. While PHMSA officials stated that “less prescriptive” does not 

necessarily mean less safe, they also stated that distribution integrity 

management requirements for distribution pipelines can be more difficult 

to enforce than integrity management requirements for transmission 

pipelines.

In general, the effect of changing PHMSA’s requirement for low-stress 

transmission pipelines for pipeline safety is unclear. While the 

consequences of a low-stress transmission pipeline failure are generally 

not severe because these pipelines are more likely to leak than rupture, 

the point at which a gas pipeline fails by rupture is uncertain and depends 

on a number of factors in addition to pressure, such as the size or type of 

defect and the materials used to conduct the pipeline. In addition, the 

mileage and location of pipelines that would be affected by such a 

regulatory change are currently unknown, although PHMSA recently 

changed its reporting requirements to collect such information. The 

concern is that because distribution pipelines are located in highly 

populated areas, the low-stress transmission pipelines that are connected 

to them could also be located in highly populated areas. As a result, we 

considered the current regulatory approach of applying more prescriptive 

transmission pipeline requirements reasonable.
Appendix II: Examples of Pipeline Incident 

Response Times

Page 15 GAO-13-284T Pipeline Safety 

Operators we spoke with stated that the amount of time it takes to 

respond to an incident can vary depending on a number of variables (see 

table 2).

Table 2: Examples of Response Times in Select Pipeline Incidents from 2009 to 2011

Incident 

response time Description

1 minute A rupture on a natural-gas transmission pipeline located underground in a sparsely populated area was caused 

when a construction company worker accidentally struck the pipeline, which then ignited and exploded. When the 

line broke, automatic-shutoff valves on either side of the rupture closed within one minute. Despite the fast valve 

closure, the explosion caused one fatality—the worker who struck the pipeline—and injured seven others. The 

affected pipeline segment was 20 miles long. Though the valves were closed, there was enough gas remaining in 

the pipeline to fuel the fire for several hours. In addition to causing a fatality and injuries, the incident cost the 

operator an estimated $1 million, due primarily to the value of the lost product ($740,000), as well as damage to 

the pipeline ($288,000).

3 minutes A rupture on a hazardous liquid transmission pipeline, located underground near a creek in a sparsely populated 

area, was caused when heavy rains shifted the land which broke the pipeline, releasing over 1,700 barrels of 

propane. The line break was immediately picked up by the operator’s computer-based leak detection system, and 

operator personnel on site closed manual valves to isolate the segment within 3 minutes. Because propane is a 

highly volatile liquid, which turns to gas when released into the atmosphere, there was no soil or water 

contamination or environmental cleanup costs. The incident cost the operator an estimated $128,000, due 

primarily to the cost of repairs ($73,000) and value of lost product ($55,000).

8 minutes During the night, unknown individuals operating construction equipment punctured a hazardous liquid transmission 

pipeline located underground in an environmentally sensitive area, causing 56 barrels of crude oil to leak into the 

soil. The puncture caused a drop in pressure that the control room operator detected in 2 minutes. Six minutes

later, the control room operator shut down the pipeline and isolated the affected segment with remotely controlled 

valves. About 2 hours later, the operator’s response personnel arrived on site. The incident cost the operator an 

estimated $1.3 million, due primarily to its environmental remediation efforts ($1 million) and emergency response 

($250,000).

2 hours A crack on an above-ground portion of a hazardous liquid pipeline, located in a populated area, caused 120 

barrels of crude oil to spray into the air. About 15 minutes after the incident started, a local resident reported to the 

fire department that crude oil was spraying into the air at a pipeline station. The fire department went to the 

incident site and, about 30 minutes after the initial call, notified the pipeline operator of a broken oil pipeline. About 

20 minutes after receiving the fire department’s call, the control room began shutting down the pipeline system 

and isolating the affected segment by ordering the closure of the upstream valve. Approximately 50 minutes 

later—about 2 hours after the incident started—response personnel arrived on site and manually closed the valve, 

which stopped the leak. The incident cost the operator an estimated $183,000, due primarily to its emergency 

response ($118,000) and environmental remediation efforts ($61,000).

7 days A natural gas transmission pipeline, located underground in a sparsely populated area, developed a small leak as 

the result of a construction defect. The operator did not discover the leak on the pipeline for almost a week 

following initial reports due to the size of the leak in combination with wind gusts in the area that dissipated the 

escaping natural gas, reducing the common signs of a gas leak, such as the smell and damage to vegetation. 

Once the operator detected the leak during routine, periodic external monitoring of the pipeline, it took over a day 

to identify its exact location. The incident cost the operator an estimated $128,000 in repairs ($106,000) and lost 

product ($22,000).

Source: GAO presentation of information obtained during interviews with pipeline operators.

Appendix II: Examples of Pipeline Incident 

Response Times

(541104)
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