PIPELINE SAFETY

Better Data and 

Guidance Needed to 

Improve Pipeline 

Operator Incident 

Response

Report to Congressional Committees

January 2013

GAO-13-168

United States Government Accountability Office

GAO
United States Government Accountability Office

Highlights of GAO-13-168, a report to 

congressional committees

January 2013

PIPELINE SAFETY

Better Data and Guidance Needed to Improve 

Pipeline Operator Incident Response

Why GAO Did This Study

The nation’s 2.5 million mile network of 

hazardous liquid and natural gas 

pipelines includes more than 400,000

miles of “transmission” pipelines, which

transport products from processing 

facilities to communities and largevolume users. To minimize the risk of 

leaks and ruptures, PHMSA requires 

pipeline operators to develop incident 

response plans. Pipeline operators 

with pipelines in highly populated and 

environmentally sensitive areas (“highconsequence areas”) are also required 

to consider installing automated 

valves. 

The Pipeline Safety, Regulatory 

Certainty, and Job Creation Act of 

2011 directed GAO to examine the 

ability of transmission pipeline 

operators to respond to a product

release. Accordingly, GAO examined

(1) opportunities to improve the ability 

of transmission pipeline operators to 

respond to incidents and (2) the 

advantages and disadvantages of 

installing automated valves in highconsequence areas and ways that 

PHMSA can assist operators in 

deciding whether to install valves in 

these areas. GAO examined incident 

data; conducted a literature review; 

and interviewed selected operators, 

industry stakeholders, state pipeline 

safety offices, and PHMSA officials. 

What GAO Recommends

DOT should (1) improve incident 

response data and use these data to

evaluate whether to implement a 

performance-based framework for

incident response times and (2) share 

guidance and information on

evaluation approaches to inform

operators’ decisions. DOT agreed to 

consider these recommendations.

What GAO Found

The Department of Transportation’s (DOT) Pipeline and Hazardous Materials 

Safety Administration (PHMSA) has an opportunity to improve the ability of 

pipeline operators to respond to incidents by developing a performance-based 

approach for incident response times. The ability of transmission pipeline 

operators to respond to incidents—such as leaks and ruptures—is affected by 

numerous variables, some of which are under operators’ control. For example, 

the use of different valve types (manual valves or “automated” valves that can be 

closed automatically or remotely) and the location of response personnel can 

affect the amount of time it takes for operators to respond to incidents. Variables 

outside of operators’ control, such as weather conditions, can also influence 

incident response time, which can range from minutes to days. GAO has 

previously reported that a performance-based approach—including goals and 

associated performance measures and targets—can allow those being regulated 

to determine the most appropriate way to achieve desired outcomes. In addition, 

several organizations in the pipeline industry have developed methods for 

quantitatively evaluating response times to incidents, including setting specific, 

measurable performance goals. 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). However, PHMSA must 

first improve the data it collects on incident response times. These data are not 

reliable both because operators are not required to fill out certain time-related 

fields in the reporting form and because operators told us they interpret these

data fields in different ways. Reliable data would improve PHMSA’s ability to 

measure incident response and assist the agency in exploring the feasibility of 

developing a performance-based approach for improving operator response to 

pipeline incidents. 

The primary advantage of installing automated valves is that operators can

respond quickly to isolate the affected pipeline segment and reduce the amount 

of product released; however, automated valves can have disadvantages, 

including the potential for accidental closures—which can lead to loss of service 

to customers or even cause a rupture—and monetary costs. Because the 

advantages and disadvantages of installing an automated valve are closely 

related to the specifics of the valve’s location, it is appropriate to decide whether 

to install automated valves on a case-by-case basis. Several operators we spoke 

with have developed approaches to evaluate the advantages and disadvantages 

of installing automated valves. For example, some operators of hazardous liquid

pipelines use spill-modeling software to estimate the amount of product release 

and extent of damage that would occur in the event of an incident. 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. Furthermore, not all operators we spoke with were 

aware of existing PHMSA guidance designed to assist operators in making these 

decisions. PHMSA could assist operators in making this decision by formally 

collecting and sharing evaluation approaches and ensuring operators are aware 

of existing guidance. 

View GAO-13-168. For more information, 

contact Susan A. Fleming at (202) 512-2834 

or flemings@gao.gov.
Page i GAO-13-168 Pipeline Safety

Letter 1 

Background 5

Performance-Based Approach Offers Opportunity to Improve 

Incident Response, but Better Data Are Needed 12

Improved Information Sharing about Evaluating Automated Valve 

Advantages and Disadvantages Could Inform Operators’ 

Decisions 23

Conclusions 29

Recommendations for Executive Action 30

Agency Comments 30

Appendix I Objectives, Scope, and Methodology 32

Appendix II How Select Operators Determined Whether to Install 

Automated Valves 36

Appendix III Automated Valve Costs 43

Appendix IV GAO Contact and Staff Acknowledgments 45

Tables

Table 1: Examples of Response Times in Select Pipeline Incidents 

from 2009 to 2011 17

Table 2: Advantages and Disadvantages of Installing Automated 

Valves on Pipelines 24

Table 3: Range of Equipment and Labor Costs, According to 

Pipeline Vendors and Contractors 44

Figures

Figure 1: Transmission Pipeline across the United States, as of 

September 2012 6

Figure 2: Steps Operators Take When Responding to Incidents 10

Contents 
Page ii GAO-13-168 Pipeline Safety

Figure 3: A Hand Wheel Used to Close a Manual Valve (Outlined in 

Red on Left) and an Actuator Used to Remotely Close an 

Automated Valve (Outlined in Red on Right) 12

Abbreviations

DOT Department of Transportation

NTSB National Transportation Safety Board

PHMSA Pipeline and Hazardous Materials Safety Administration

This is a work of the U.S. government and is not subject to copyright protection in the 

United States. The published product may be reproduced and distributed in its entirety 

without further permission from GAO. However, because this work may contain 

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Page 1 GAO-13-168 Pipeline Safety

United States Government Accountability Office

Washington, DC 20548

January 23, 2013

The Honorable John D. Rockefeller IV

Chairman

The Honorable Ranking Member

Committee on Commerce, Science, and Transportation

United States Senate

The Honorable Fred Upton

Chairman

The Honorable Henry Waxman

Ranking Member

Committee on Energy and Commerce

House of Representatives

The Honorable Bill Shuster

Chairman

The Honorable Nick J. Rahall

Ranking Member

Committee on Transportation and Infrastructure

House of Representatives

The United States has over 2.5 million miles of hazardous liquid and 

natural gas pipelines that transport approximately 65 percent of the 

energy we consume. These pipelines, which are largely regulated by the 

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

Safety Administration (PHMSA), are relatively safe when compared with 

other modes of transporting hazardous goods (e.g., highway and rail). 

However, when pipelines leak or rupture the results can be devastating, 

including fatalities, injuries, and extensive property or environmental 

damage. Such an “incident” occurred in September 2010 in San Bruno, 

California, killing 8 people and damaging or destroying over 100 homes.1

To minimize the risk of a pipeline incident, pipeline operators are required 

to develop leak detection methods and emergency response plans. 

Operators with pipelines in highly populated or environmentally sensitive 

areas (called “high-consequence areas”) are subject to supplemental risk-

 

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 report will refer to both as “incidents.” 

 
 

Page 2 GAO-13-168 Pipeline Safety

based regulations under PHMSA’s integrity management program.2

Through this program, PHMSA requires that operators conduct a risk 

assessment to determine what additional measures to take to mitigate the 

consequences of pipeline failures. One mitigation measure operators can 

take based on the results of the risk assessment is to install automated 

valves, which in the event of an incident, close automatically or are closed 

remotely by operators in a control room.3 Since 1971, the National 

Transportation Safety Board (NTSB) has made recommendations that 

DOT develop standards and requirements for automated valves. 

Following the San Bruno incident, NTSB recommended that DOT require 

natural gas pipeline operators install automated valves in all highconsequence areas.4

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 

mandated that GAO examine the ability of transmission pipeline5

operators to respond to a hazardous liquid or natural gas release from an 

 

2

“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. 

3

For the purposes of this report we use the term “install an automated valve” to refer 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.

4

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). According to NTSB, PHMSA is in 

the process of responding to this recommendation. Specifically, in August 2011, PHMSA 

began a rulemaking process that could address the extent to which operators will be 

required to install automated valves. 76 Fed. Reg. 53086 (Aug. 25, 2011).

5

For the purposes of this report, we use the term “transmission pipeline” to refer to both 

onshore hazardous liquid and natural gas pipelines carrying product over long distances 

to users.
 

Page 3 GAO-13-168 Pipeline Safety

existing pipeline segment.6 Accordingly, this report contains information 

on: (1) opportunities to improve the ability of transmission pipeline 

operators to respond to incidents, and (2) the advantages and 

disadvantages of installing automated valves in high-consequence areas 

and ways that PHMSA can assist operators in deciding whether to install 

valves in these areas.

To determine what opportunities exist to improve the ability of 

transmission pipeline operators to respond to incidents, we identified the 

variables that influence operators’ incident response capabilities. To do 

so, we spoke with selected operators about their prior incidents and 

variables that influenced their ability to respond. Operators were selected 

based on criteria, including amount and types of pipeline owned in highconsequence areas7 and geographic diversity. We also discussed prior 

incidents, incident response times, and federal oversight of the pipeline 

industry with officials from PHMSA, state pipeline safety offices, industry 

associations, and safety groups. Based on our discussions and review of 

prior incidents, we identified variables that influence operators’ ability to 

respond to incidents. We also examined 2007 to 2011 PHMSA incident 

data, including data on:

• total number of incidents;

• type of incident (leak or rupture);

• type of pipeline where the incident occurred; and

• the dates and times when an incident occurred, the operator identified 

the incident, the operator’s resources (personnel and equipment) 

arrived on site, and the operator shut down a pipeline or facility.

 

6

The Act also 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). In response, PHMSA contracted with Oak Ridge National Laboratory to draft a 

study, which found that automated valves were feasible under certain conditions. 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).

7

According to 2010 PHMSA data, the eight operators we selected represented 19 percent 

of hazardous liquid and 10 percent of natural gas miles in these areas. There were 682 

hazardous liquid and natural gas transmission pipeline operators with 98,013 pipeline 

miles in high-consequence areas.
 

Page 4 GAO-13-168 Pipeline Safety

We assessed the reliability of data through discussions with PHMSA 

officials and select operators and determined that data elements related 

to numbers of incidents, types of releases, and types of pipeline where 

incidents occurred were reliable for the purpose of providing context. 

However, we determined that data elements related to response time 

were not sufficiently reliable for the purpose of conducting a detailed 

analysis of relationships between response time and other factors. 

Finally, we reviewed federal requirements, and industry and government 

performance standards related to emergency response within the pipeline 

industry.

To determine the advantages and disadvantages of installing automated 

valves in high-consequence areas and ways that PHMSA can assist 

operators in deciding whether to install these valves, we identified the key 

factors that should be used in deciding whether to install automated 

valves in high-consequence areas. To do so, we conducted a literature 

review of previous research dating back to 1995 and interviewed officials 

from industry associations and pipeline safety groups. In addition, we 

collected information from selected operators on their methods for 

deciding whether to install automated valves, as well as specific pipeline 

segments and valve locations on which they made such decisions. We 

also discussed the regulations with officials from PHMSA, state pipeline 

safety offices, and pipeline operators to determine what, if any, additional 

guidance would help operators apply the current regulations on installing 

automated valves. For further details on our scope and methodology, see 

appendix I.

We conducted this performance audit from March 2012 to January 2013 

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.
 

Page 5 GAO-13-168 Pipeline Safety

Three main types of pipelines carry hazardous liquid8 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.

 

8

Hazardous liquid products include petroleum (crude oil, condensate, natural gasoline, 

natural gas liquids, and liquefied petroleum gas); petroleum products (flammable, toxic, or 

corrosive products obtained from distilling and processing of crude oil, unfinished oils, 

natural gas liquids, blend stocks, and other miscellaneous hydrocarbon compounds); and 

anhydrous ammonia.

Background 
 

Page 6 GAO-13-168 Pipeline Safety

Figure 1: Transmission Pipeline across the United States, as of September 2012

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 
 

Page 7 GAO-13-168 Pipeline Safety

PHMSA must meet.9 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.10

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.”

11 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 

 

9

PHMSA does not regulate all pipelines. For example, many gathering pipelines have not 

been subject to PHMSA regulations because they are generally located away from 

population centers and operate at low pressures. 

10PHMSA 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.

11PHMSA established requirements (49 C.F.R. § 195.452) for integrity management for 

hazardous liquid pipeline operators with 500 or more miles of pipelines in December 2000 

(65 Fed. Reg. 75378, (Dec. 1, 2000)) and for operators with less than 500 miles in 

January 2002 (67 Fed. Reg. 2136, (Jan.16, 2002)). In 2003, PHMSA issued integrity 

management regulations for all operators of gas transmission pipelines (68 Fed. Reg. 

69778, (Dec.15, 2003)).
 

Page 8 GAO-13-168 Pipeline Safety

issuing warning letters, notices of probable violation, notices of 

amendment, notices of proposed safety order, corrective action orders, 

and imposing civil penalties.12

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.13 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.

 

12Warning letters are issued for lower risk probable violations and program deficiencies. 

Through such letters PHMSA notifies the operator of the alleged violations and directs it to 

correct them or be subject to further enforcement action. Notices of probable violation

allege specific regulatory violations and, where applicable, propose corrective action in a 

compliance order and/or civil penalties. The operator has a right to respond and request 

an administrative hearing. Notices of amendment allege that an operator’s plans and 

procedures are inadequate and require that they be amended. The operator has a right to 

respond and request an administrative hearing. Notices of proposed safety order notify an 

operator that a particular pipeline facility has a condition or conditions that pose a pipeline 

integrity risk to public safety, property, or the environment. These notices propose 

measures the operator must take to address the identified risk, including inspection, 

testing, and repair. Corrective action orders are issued to operators with a pipeline that 

represents a serious hazard to life, property, or the environment. The order identifies 

actions that must be taken by the operator to assure safe operation, including the 

shutdown of a pipeline or operation at reduced pressure, physical inspection or testing of 

the pipeline, and repair or replacement of defective pipeline segments, among other 

actions.

13The risks and consequences posed by gas and hazardous liquids incidents also differ. 

Natural gas tends to ignite more easily, resulting in more explosions. Hazardous liquids 

ignite less easily, but can spill and pollute the environment.
 

Page 9 GAO-13-168 Pipeline Safety

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,14 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.

 

14The National Response Center is the sole federal point of contact for reporting oil and 

chemical spills. 
 

Page 10 GAO-13-168 Pipeline Safety

Figure 2: Steps Operators Take When Responding to Incidents

a

Some incidents, such as very small leaks, do not create a hazardous condition and may not require 

an immediate response from the operator. The operator can address these non-emergency incidents 

while maintaining normal operations.

b

Emergency shutdown procedures can be initiated remotely by control room operators or through 

personnel in the field.

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 
 

Page 11 GAO-13-168 Pipeline Safety

readings.15,16 (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,17 while integrity management regulations require that 

transmission pipeline operators conduct a risk assessment for highconsequence areas that includes the consideration of automated 

valves.18

 

15Hazardous 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). For the purposes of this report we 

describe all of these valves as automated valves.

16PHMSA does not collect data on the number of manual and automated valves. The 

Interstate Natural Gas Association of America—the primary industry group for natural gas 

transmission pipelines—has collected valve equipment information for almost half of the 

300,000 miles of natural gas transmission pipeline in the United States and reports that of 

the 29,827 valves reported 5,013, or 17 percent, are automated. In highly populated and 

frequented locations 1,972, or 23 percent, of the 8,693 total valves, were automated. 

1749 C.F.R. §§ 192.179, 195.260.

18Automated valves are one of several measures that operators can take to prevent and 

mitigate the consequences of a pipeline incident. Other measures include additional leak 

detection and damage prevention activities.
 

Page 12 GAO-13-168 Pipeline Safety

Figure 3: A Hand Wheel Used to Close a Manual Valve (Outlined in Red on Left) and an Actuator Used to Remotely Close an 

Automated Valve (Outlined in Red on Right)

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 performancebased 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.

Performance-Based 

Approach Offers 

Opportunity to 

Improve Incident 

Response, but Better 

Data Are Needed 
 

Page 13 GAO-13-168 Pipeline Safety

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.19 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.

 

19Hazardous liquid pipeline operators are required to have a leak detection system on 

their pipeline. Natural gas pipeline operators may choose to install a leak detection 

system, although they are required to periodically survey their pipeline to identify leaks.

Incident Response Time 

Depends on Multiple 

Variables, Some of Which 

Operators Can Control
 

Page 14 GAO-13-168 Pipeline Safety

• 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. 

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. However, if 

affected valves happen to be located at or close to facilities where 

personnel are permanently stationed, the type of valve could be less 

critical in influencing incident response time.

• Control room management. Clear operating policies and shutdown 

protocols for control room personnel can influence response time to 

incidents.20 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. A few of 

the operators we met with told us that while in the past it was a 

common practice in the industry to avoid shutdowns unless absolutely 

necessary, the practice now for these operators is to shut down the 

line if there is any doubt about safety. An official from one natural gas 

pipeline operator told us that his company instructs control room 

personnel that they will not suffer repercussions from shutting down a 

line for safety reasons. Another official from a hazardous liquid 

pipeline operator told us that the authority to shut down is at the 

control room level and that even personnel in the field can make the 

call to shut down a line.

 

20PHMSA requires pipeline operators to develop and follow written control room 

management procedures that define the roles and responsibilities of control room 

personnel in normal, abnormal, and emergency operating situations. This requirement 

allows individual operators to define the specific responsibilities for control room 

management by considering the characteristics of the operator’s pipeline and its methods 

of safely managing pipeline operation.
 

Page 15 GAO-13-168 Pipeline Safety

• 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.21 For example, one natural gas pipeline operator 

told us that during one incident, the local first responders had turned 

to the operator personnel for direction on how to respond to a rupture. 

As a result, the operator said that one of the lessons learned was that 

the company needed to conduct more emergency response 

exercises, such as mock drills, with the local first responders so the 

responders would know their roles and responsibilities.

We identified four other variables that influence a pipeline operator’s 

ability to respond to an incident, but are beyond an operator’s control:

• Type of release. The type of release—leak or rupture—can influence 

how quickly an operator responds to an incident. 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 time of day when an incident occurs can affect 

incident response time. 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. For example, 

one natural gas pipeline operator told us about an incident that 

occurred on a Saturday afternoon, which meant that traffic did not 

delay response personnel traveling to the scene.

• Weather conditions. Weather conditions can affect how quickly an 

operator can respond to an incident. For example, one natural gas 

pipeline operator described an incident caused by a hurricane’s storm 

 

21PHMSA requires pipeline operators to establish and maintain communications with fire, 

police, and other appropriate public officials to learn the responsibility and resources of 

each government organization that may respond to a natural gas or hazardous liquid 

pipeline emergency and acquaint the officials with the operator’s ability in responding to 

an emergency. Operators must also plan and coordinate their responses to emergency 

incidents with these officials. 
 

Page 16 GAO-13-168 Pipeline Safety

surge that pushed debris into the pipeline at a facility, and flooding 

prevented the response personnel from reaching the site for several 

days, during which time the pipe continued to leak gas. Winter 

conditions can also make it more difficult for the operator’s response 

personnel to reach a facility or to access valve sites in remote areas. 

As another example, windy conditions can disperse natural gas and 

make it hard to detect a leak.

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

own pipeline in a shared right of way,22 determining whose system is 

affected can increase incident response time. Operators may delay 

responding if they have not confirmed that the incident is on their 

pipeline. For example, one natural gas pipeline operator told us about 

an incident that took 2 days to repair because when their personnel 

first detected a leak, the personnel initially contacted another 

operator, whose line crossed over theirs, to make sure the leak was 

not the other operator’s.

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

respond to an incident can depend on all of the variables listed above and 

can range from several minutes to days (see table 1).

 

22A right of way is a strip of land, usually between 25 to 150 feet wide, containing one or 

more pipelines.
 

Page 17 GAO-13-168 Pipeline Safety

Table 1: 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 remote-control valves. About two 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.
 

Page 18 GAO-13-168 Pipeline Safety

We and others have recommended that the federal government move 

toward performance-based regulatory approaches to allow those being 

regulated to determine the most appropriate way to achieve desired, 

measurable outcomes.23 For example, Executive Order 13563 calls for 

improvements to the nation’s regulatory system, including the use of the 

best, most innovative and least burdensome tools for achieving regulatory 

ends.24 We have also previously reported on the benefits of a 

performance-based framework,25 which helps agencies focus on 

achieving outcomes.26 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 towards goals.

PHMSA has included these three elements of a performance-based 

framework in some aspects of its pipeline safety program, but not for 

incident response times. For example, PHMSA has set national goals 

intended to reduce the number of pipeline incidents involving fatality or 

major injury and the number of hazardous liquid pipeline spills with 

environmental consequences. Each of these national goals has 

associated performance measures (i.e., the number of such incidents) 

and specific targets (such as reducing the number of incidents involving a 

fatality or major injury from 39 to less than 28 per year by 2016) that allow 

PHMSA to track its progress toward the goals. However, while PHMSA 

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

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

 

23We consider performance-based regulations those that focus on desired, measurable 

outcomes, rather than prescriptive processes, techniques, or procedures.

2476 Fed. Reg. 3821, § 1 (a), (b)(4) (Jan. 21, 2011).

25GAO, Statewide Transportation Planning: Opportunities Exist to Transition to 

Performance-Based Planning and Federal Oversight, GAO-11-77 (Washington, D.C.: 

December 2010).

26In 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.

A Performance-Based 

Approach Could Improve 

Incident Response Times
 

Page 19 GAO-13-168 Pipeline Safety

directs operators to respond to certain incidents–emergencies that require 

an immediate response–in a “prompt and effective” manner,27 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. PHMSA 

officials told us that because each incident presents unique 

circumstances, its inspectors must determine whether an operator’s 

incident response was prompt and effective on a case-by-case basis. 

According to PHMSA, in making this determination, inspectors must use 

their professional judgment to balance any challenges the operator faced 

in responding with the operator’s obligation to the public’s safety.

Other organizations in the pipeline industry, including some state 

regulatory agencies, have developed methods for measuring the 

performance of operators responding to incidents by using specific 

incident response times. 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. For example, the New 

Hampshire Public Utilities Commission has established incident response 

time standards—ranging from 30 to 60 minutes, with performance 

targets—for natural gas distribution companies to meet when responding 

to reports of a leak.28 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 

 

27Emergencies 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.

28According to these standards, gas distribution companies have three response time 

targets—30 minutes, 45 minutes, and 60 minutes—which companies must meet between 

76 to 97 percent of the time, depending on the response time target and the operator’s 

working hours when the call is received (i.e., normal business hours, after hours, and 

weekends/holidays). For example, gas distribution companies are expected to achieve a 

30-minute response 76 percent of the time during weekends and holidays, but 82 percent 

of the time during normal business hours. These response time standards also apply to 

other events, such as odor complaints or reports of damage to the pipeline.
 

Page 20 GAO-13-168 Pipeline Safety

pipelines in highly populated areas.29 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.

According to PHMSA officials, pipeline incidents often have unique 

characteristics, so developing a performance measure and associated 

target for incident response time similar to those used by other pipeline 

organizations 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. Officials stated that the intention behind requiring operators to 

respond promptly and effectively is to make the area safe as quickly as 

possible. In some instances, an operator can accomplish this outcome in 

the time it takes to close valves and isolate pipeline segments, while in 

other instances, an operator might need to completely vent or drain the 

product from the pipeline. Likewise, it would be difficult to identify a 

specific target for incident response time, as pipeline operators likely 

should respond to some incidents more quickly than others. For example, 

industry officials noted that while most fatalities and injuries caused by a 

pipeline explosion occur in the initial blast, a faster incident response time 

could help reduce fatalities and injuries in cases where there are sites 

nearby whose occupants have limited mobility (e.g., prisons, hospitals). In 

these situations, operators told us they want to ensure their incident 

response time is faster than for more remote locations where an 

explosion would have less of an impact on people, property, and the 

environment.

Although defining performance measures and targets for incident 

response can be challenging, one 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 

 

29According to officials from the Interstate Natural Gas Association of America, which 

represents natural gas transmission pipeline operators, members will conduct a risk 

analysis on a case-by-case basis to determine the appropriate maximum incident 

response time for small diameter (i.e., 12 inches or less) natural gas pipelines in highly 

populated areas. Prior to the 1-hour goal for large diameter pipelines, members did not 

have any incident response time commitment.
 

Page 21 GAO-13-168 Pipeline Safety

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. 

Furthermore, as part of this analysis of response times for various types 

of pipelines, PHMSA could explore the feasibility of integrating incident 

response performance measures and targets for individual pipelines into 

its integrity management program. For example, PHMSA might identify 

performance measures that are appropriate for various types of pipelines 

and allow operators to determine which measures and targets best apply 

to their individual pipeline segments, based on the characteristics of those 

segments. Such an approach would be consistent with our prior work on 

performance measurement, as it would allow operators the flexibility to 

meet response time targets in several ways, including changes to their 

leak detection methods, moving personnel closer to the valve location, or 

installing automated valves. PHMSA would then review an operator’s 

selection of measures and targets as part of ongoing integrity 

management inspections; this process is similar to how inspectors review 

other provisions in the integrity management program.

PHMSA would need reliable national data to implement a performancebased framework for incident response times to ensure operators are 

responding in a prompt and effective manner.30 However, the data 

currently collected by PHMSA do not enable them to accurately 

determine incident response times for all recent incidents 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. Specifically, PHMSA requires operators to report the date 

and time when the incident occurred. Operators are not required to report

the dates and times when:

• the operator identified the incident;

• the operator’s resources (personnel or equipment) arrived on site; and

• the operator shut down and restarted a pipeline or facility.

 

30We have reported on the need for comprehensive and reliable data to implement a 

performance-based approach. See GAO, Surface Transportation: Restructured Federal 

Approach Needed for More Focused, Performance-Based, and Sustainable Programs, 

GAO-08-400 (Washington, D.C.: Mar. 6, 2008). 

PHMSA Data on Incident 

Response Time Are 

Limited
 

Page 22 GAO-13-168 Pipeline Safety

As a result, our analysis determined that hazardous liquid pipeline 

operators did not report the date and time for two of these variables—

when the incident was identified and when operator resources arrived on 

site—for 26 percent (178 out of 674) of incidents that occurred in 2010 

and 2011. Also, these operators did not identify whether a shutdown took 

place in 16 percent (108 out 674) of incidents over the same time 

period.31 In comparison, natural gas pipeline operators reported more 

complete data; these operators did not report data for when the operator 

identified the incident and resources arrived on site in only 3 percent (6 

out of 191) of incidents that occurred in 2010 and 2011. Also, these 

operators did not identify whether a shutdown took place in only about 2 

percent (3 out of 191) of incidents over the same period. PHMSA officials 

told us that because they have not used the time-related data to identify 

safety trends, the omissions have not been a problem for them, although 

in the future they may decide to make some of these data fields 

mandatory.

In addition to omitting certain incident data fields, several officials from 

pipeline operators told us that they interpret what to include in the timerelated, incident data fields differently. For example, according to one 

official from a natural gas operator, some operators interpret the time 

when an operator identified the incident as the time when operator 

personnel first received a call about a potential leak, while others may 

interpret the time when an operator identified an incident as the time 

when operator personnel received an on-site confirmation of a leak. 

These differing interpretations occur even though guidance on PHMSA’s 

 

31The DOT Inspector General has also reported on significant data problems with PHMSA 

hazardous liquid pipeline operator data. In its 2012 audit, the DOT Inspector General 

identified shortcomings in PHMSA data management and quality that limit the usefulness 

of incident and annual report data. For example, according to the audit, PHMSA lacks a 

method to detect duplicate reporting of annual shipment volumes from one year to the 

next. PHMSA reported that it created a data quality assurance plan in 2010 and has 

implemented many improvements in its pipeline safety data systems, but still faces 

significant staffing and funding needs to make further improvements. See Office of 

Inspector General, U.S. Department of Transportation, Hazardous Liquid Pipeline 

Operators’ Integrity Management Programs Need More Rigorous PHMSA Oversight, AV2012-140 (Washington, D.C.: June, 2012).
 

Page 23 GAO-13-168 Pipeline Safety

website instructs operators how to complete the reporting forms, including 

the time-related data fields.32

The primary advantage of installing automated valves is reducing the time 

to shut down and isolate a pipeline segment after a leak or rupture 

occurs, while disadvantages include the potential for accidental closures 

and monetary cost. Because these advantages and disadvantages vary 

among valve locations, operators should make decisions about whether 

to install automated valves—as opposed to other safety measures—on a 

case-by-case basis. PHMSA has several opportunities to assist operators 

in making these evaluations, including communicating guidance and 

sharing information on some methods operators use to make these 

decisions.

Research and industry stakeholders indicate that the primary advantage 

of installing automated valves 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 the initial blast, quickly isolating the 

pipeline segment through automated valves can significantly reduce 

subsequent damage by reducing the amount of hazardous liquid and 

natural gas released. For example, NTSB found that automated valves 

would have reduced the amount of time taken to stop the flow of natural 

gas in the San Bruno incident and, therefore, reduced the severity of 

property damage and life-threatening risks to residents and emergency 

responders.33 According to research and industry stakeholders, 

automated valves will only decrease the number of fatalities and injuries

in those cases when people cannot easily evacuate the area, such as 

cases involving hospital patients or prison inmates.

Research and industry stakeholders identified several disadvantages 

operators should consider when determining whether to install automated 

 

32PHMSA guidance states that when reporting on when an operator identified the incident, 

operators should enter the date and time when the operator became aware or first 

identified when the incident had occurred, and not when the operator determined that the 

incident met the reporting criteria.

33NTSB, 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).

Improved Information 

Sharing about 

Evaluating Automated 

Valve Advantages and 

Disadvantages Could 

Inform Operators’ 

Decisions 

Improved Response Times, 

Potential for Accidental 

Closures, and Costs 

Should be Evaluated on a 

Case-by-Case Basis
 

Page 24 GAO-13-168 Pipeline Safety

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. 

For example, according to a pipeline operator, an accidental closure on a 

natural gas pipeline in New Jersey resulted in significant disruption and 

downstream curtailments to customers in New York City during high 

winter demand. In addition, the monetary costs of installing automated 

valves can range from tens of thousands to a million dollars per valve, 

which may be significant expenditures for some pipeline operators.34 (See 

table 2.)

Table 2: Advantages and Disadvantages of Installing Automated Valves on Pipelines

Advantages Improved response time • Can reduce injuries and fatalities for some locations, such as hospitals or 

prisons, where people cannot evacuate quickly.

• Can reduce the amount of damage by limiting the amount of fuel for secondary 

fire(s) and environmental cleanup.

• Can allow operator personnel and emergency responders to access the 

affected segment more quickly and safely.

• Can reduce the potential monetary cost of an incident for the operator by 

limiting the amount of product lost.

Disadvantages Accidental closures • For natural gas pipelines, accidental closures can result in the loss of service to 

utilities and critical customers (e.g., winter-time outages can leave people 

without heat).

• For hazardous liquid pipelines, accidental closures can cause an incident, when 

a valve closes and the subsequent pressure buildup causes the pipeline to 

rupture.

Monetary costs • Requires operators to purchase equipment, including devices to remotely 

communicate or sense pressure drops, actuators to close the valve, and power 

sources for this new equipment.

• Requires operators to take on installation costs, which can involve temporarily 

shutting down the pipeline, purging the product from the pipeline, and pulling 

product from the market. Operators may also have costs related to accessing 

the valve location (e.g., right of way, permitting, and physical space to install the 

new equipment) and updating their leak detection technologies.

• May require operators to incur additional recurring costs to train staff, maintain 

the valves, increase security, and conduct inspections of the new valve.

Source: GAO analysis of research and industry stakeholder opinions.

Research and industry stakeholders also indicate the importance of 

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

 

34See below and appendix III for a discussion on the costs of automated valves. 
 

Page 25 GAO-13-168 Pipeline Safety

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 location, the likelihood of an ignition, type of 

product being transported, operating pressure, topography and pipeline 

diameter, among others, all play a role in determining the extent to which 

an automated valve would be advantageous.

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

whether to install automated valves. One of the eight operators we met 

with had decided to install automatic-shutoff valves across its pipeline 

system, regardless of risk, to eliminate the need for control room staff to 

make judgment calls on whether or not to close valves to isolate pipeline 

segments. However, seven of the eight operators we met with developed 

their own risk-based approach for considering potential advantages and 

disadvantages when making these decisions on a case-by-case basis. 

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 yesor-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 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. These seven 

operators told us that their approaches for making decisions about 

whether to install automated valves considered the advantages and the 

disadvantages we identified above.35

• Improved response time. Most operators we spoke with considered 

whether automated valves would lead to a faster response time. For 

example, the primary criterion used by two of the natural gas pipeline 

operators was the amount of time it would take to shut down the 

pipeline and isolate the segment and population along the segment. In 

one instance, an operator decided to install a remote-control valve in 

a location that would take pipeline personnel 2.5 hours to reach and 

30 minutes more to close the valve. Installing the automated valve is 

 

35See appendix II for more details on the methods used by each operator to determine 

whether or not to install automated valves.

Operators Have Developed 

Approaches to Evaluate 

Advantages and 

Disadvantages of Installing 

Automated Valves
 

Page 26 GAO-13-168 Pipeline Safety

expected to reduce the total response time to under an hour, including 

detecting the incident and making the decision to isolate the pipeline 

segment. In addition, several hazardous liquid pipeline operators used 

spill modeling to determine whether an automated valve would result 

in a reduced amount of damage from product release at individual 

locations. This spill modeling typically considered topography, 

operating pressure, and placement of existing valves. For example, 

one hazardous liquid pipeline operator used spill modeling to make 

the decision to install a remote-control valve on a pipeline segment 

with a large elevation change after evaluating the spill volume 

reduction.

• Accidental closures. Operators indicated that installing automated 

valves, especially automatic-shutoff valves, could have unintended 

consequences, which they considered as part of their decisions to 

install automated valves. For example, two natural gas pipeline 

operators considered whether there is the potential for accidentally 

cutting off service when assessing individual locations for the possible 

installation of an automatic-shutoff valve. As noted, one natural gas 

pipeline operator has made the decision to install automatic-shutoff 

valves across its pipeline system. The operator stated that in the past, 

there were concerns with relying on automatic-shutoff valves because 

of the possibility for accidental closures, but the operator believes it 

has developed a process that effectively adapts to pressure and flow 

change and minimizes or eliminates the risk of the valve accidentally 

closing. Other natural gas pipeline operators stated that relying on 

pressure sensing systems can be dangerous because “tuning” the 

pressure activation in an effort to avoid accidental closures can result 

in situations where the valve will not automatically close during an 

actual emergency. For hazardous liquid, all operators we spoke with 

stated that they either do not consider or do not typically install 

automatic-shutoff valves because an accidental closure has the 

potential to lead to an incident. Specifically, operators stated that an 

unexpected valve closure can result in decompression waves in the 

pipeline system, which might cause the pipeline to rupture if operators 

cannot reduce the flow of product promptly.

• Monetary costs. 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 
 

Page 27 GAO-13-168 Pipeline Safety

stated that it generally supports the idea that pipeline operators 

should be given flexibility to target compliance dollars where they will 

have the most safety benefit when it is possible to do so. Operators 

we spoke with stated that they considered costs associated with 

purchasing and installing equipment. For example, four operators 

indicated that they will consider the costs related to communications 

equipment when determining whether to install automated valves. In 

addition, three operators stated that decisions to install automated 

valves are affected by whether the operator has or can gain access to 

the pipeline right of way. Other cost considerations mentioned by at 

least one operator included local construction costs and possible 

changes to leak detection systems. Finally, two natural gas pipeline 

operators stated that monetary cost plays a role in determining what 

steps they plan to take to meet a one-hour response time goal for 

pipelines in highly populated areas. For example, the operator might 

choose to move personnel closer to valves rather than installing 

automated valves, if that is the more cost-effective option.36

PHMSA has developed guidance to help operators understand current 

regulations37 on what operators must consider when deciding to install 

automated valves, but not all operators are aware of the guidance. 

PHMSA includes on its primary website two types of guidance that can be 

useful for operators in determining whether to install automated valves on 

transmission pipelines. First, PHMSA has developed inspection protocols 

for both the hazardous liquid and natural gas integrity management 

program. Second, PHMSA has developed guidance on the enforcement 

actions inspectors will take—such as a notice of proposed violation and 

warning letter, among others—should PHMSA discover a violation. Both 

of these pieces of guidance provide additional detail—not included in 

regulation—on the steps operators might take in considering whether to 

install automated valves. For example, PHMSA’s inspection protocol for 

 

36For a discussion of the costs of installing automated valves see appendix III.

37Federal regulations require hazardous liquid and natural gas pipeline operators to 

consider measures to prevent and mitigate the consequences of a pipeline failure that 

could affect a high-consequence area, including installing automated valves on individual 

pipeline segments if the operator determines such a valve would add protection and 

enhance public safety. As part of this determination, operators must consider certain 

factors at a minimum. These factors relate to descriptive characteristics of individual 

pipeline segments—such as pipeline profile and operating pressure—and consideration of 

the possible safety and environmental outcomes. See 49 C.F.R. §§ 192.935, 195.452(i).

Opportunities Exist for 

PHMSA to Better 

Communicate Guidance 

and Share Best Practices 

Operators Use to 

Determine Whether to 

Install Automated Valves
 

Page 28 GAO-13-168 Pipeline Safety

natural gas operators describes several studies on the generic costs and 

benefits of automated valves and indicates that operators may use this 

research as long as they document the reasons why the study is 

applicable to the specific pipeline segment. However, operators we spoke 

with were unaware of existing guidance to varying degrees. Specifically, 

of the eight operators we met with, three were unaware of both the 

inspection and enforcement guidance, and the remaining five operators 

were unaware of the enforcement guidance. Operators we spoke with, 

including those that were unaware of the guidance, told us that having 

this information would be helpful in making decisions to install automated 

valves. According to PHMSA, the agency provides this guidance to 

operators to ensure operators follow it as they make decisions on whether 

to install automated valves, but does not re-distribute the guidance at 

regular intervals (e.g., annually).

According to PHMSA, inspectors see examples of how operators make 

decisions to install automated valves during integrity management 

inspections, but the inspectors do not formally collect this information or 

share it with other operators. Current regulations give operators a large 

degree of flexibility in making decisions in deciding to install automated 

valves. As mentioned earlier, we spoke with operators that are using a 

variety of risk-based methods for making decisions about automated 

valves. For example, some used basic yes-or-no criteria, while others 

applied commercially available computer software to model potential 

incident outcomes. According to PHMSA, officials do not formally share 

what they view as good methods for determining whether to install 

automated valves. Officials stated they do not believe it is appropriate for 

PHMSA to publicly share decision-making approaches from a single 

operator, as doing so might be seen as an endorsement of that approach. 

However, according to PHMSA, its inspectors may informally discuss 

methods used by operators for making decisions to install automated 

valves and suggest these approaches to other operators during 

inspections. While the operators we spoke with represent roughly 18 

percent of the overall hazardous liquid and natural gas transmission 

pipelines in high-consequence areas in 2010, there are over 650 

additional pipeline operators we did not speak with that may be using 

other methods for determining whether to install automated valves. As 

such, we believe that both operators and inspectors could benefit from 

exposure to some of the methods used by other operators to make 

decisions on whether to install automated valves.

We have previously reported on the value of organizations reporting and 

sharing information and recommended that PHMSA develop methods to 
 

Page 29 GAO-13-168 Pipeline Safety

share information on practices that can help ensure pipeline safety.38

PHMSA already conducts a variety of information-sharing activities that 

could be used to ensure operators are aware of both existing guidance 

and of approaches used by other operators for making decisions to install 

valves. While, according to PHMSA officials, the agency will not endorse 

a particular operator’s approach or practice, it can and does facilitate the 

exchange of information among operators and other stakeholders. For 

example, PHMSA issues advisory alerts in the Federal Register on 

emerging safety issues, including identified mechanical defects on 

pipelines, incidents that occurred under special circumstances, and 

reminders to correctly implement safety programs (e.g., drug and alcohol 

screening). In addition, PHMSA administers a website different from its 

primary website that, according to officials, is intended to ensure 

communication with pipeline safety stakeholders, including the public, 

emergency officials, pipeline safety advocates, regulators, and pipeline 

operators.39 PHMSA also periodically conducts public workshops with 

pipeline stakeholders on a wide variety of topics, including one in March 

2012 on automated valves.

While PHMSA currently requires operators to respond to incidents in a 

“prompt and effective manner,” the agency does not define these terms or 

collect reliable data on incident response times to evaluate an operator’s 

ability to respond to incidents. A more specific response time goal may 

not be appropriate for all pipelines. However, some organizations in the 

pipeline industry believe that such a performance-based goal can allow 

operators to identify actions that could improve their ability to respond to 

incidents in a timelier manner, and are taking steps to implement a 

performance-based approach. A performance-based goal that is more 

specific than “prompt and effective” could allow operators to examine the 

numerous variables under their control within the context of an 

established time frame to understand their current ability to respond and 

identify the most effective changes to improve response times, if needed, 

on individual pipeline segments. Reliable data would improve PHMSA’s 

 

38GAO, Pipeline Safety: Collecting Data and Sharing Information on Federally 

Unregulated Gathering Pipelines Could Help Enhance Safety, GAO-12-388 (Washington, 

D.C.: Mar. 22, 2012) and GAO, Rail Transit: FTA Programs Are Helping Address Transit 

Agencies’ Safety Challenges, but Improved Performance Goals and Measures Could 

Better Focus Efforts, GAO-11-199 (Washington, D.C.: Jan. 31, 2011). 

39See http://primis.phmsa.dot.gov/comm/. 

Conclusions 
 

Page 30 GAO-13-168 Pipeline Safety

ability to measure incident response and assist the agency in exploring 

the feasibility of developing a performance-based approach for improving 

operator response to pipeline incidents.

One of the methods operators could choose to meet a performancebased approach to incident response is installing automated valves, a 

measure some operators are already taking to reduce risk. Given the

different characteristics among valve locations, it is important for 

operators to carefully weigh the potential for improved incident response 

times against any disadvantages, such as the potential for accidental 

closure and monetary costs, in deciding whether to install automated 

valves as opposed to other safety measures. However, not all operators 

we spoke with were aware of existing PHMSA guidance and PHMSA 

does not formally collect or share evaluation approaches used by other 

operators to make decisions about whether to install automated valves. 

Such information could assist operators in evaluating the advantages and 

disadvantages of these valves and help them determine whether 

automated valves are the best option for meeting a performance-based 

incident response goal.

We recommend that the Secretary of Transportation direct the PHMSA 

Administrator to take the following two actions:

• To improve operators’ incident response times, improve the reliability 

of incident response data and use these data to evaluate whether to 

implement a performance-based framework for incident response 

times.

• To assist operators in determining whether to install automated 

valves, use PHMSA’s existing information-sharing mechanisms to 

alert all pipeline operators of inspection and enforcement guidance 

that provides additional information on how to interpret regulations on 

automated valves, and to share approaches used by operators for 

making decisions on whether to install automated valves. 

We provided the Department of Transportation with a draft of this report 

for review and comment. The department had no comments and agreed 

to consider our recommendations.

Recommendations for 

Executive Action

Agency Comments 
 

Page 31 GAO-13-168 Pipeline Safety

We are sending copies of this report to relevant congressional 

committees, the Secretary of Transportation, and other interested parties. 

In addition, this report will also be available at no charge on GAO’s 

website at http://www.gao.gov. 

If you or your staff have any questions about this report, please contact 

me at (202) 512-3824 or flemings@gao.gov. Contact points for our 

Offices of Congressional Relations and Public Affairs may be found on 

the last page of this report. GAO staff who made key contributions to this 

report are listed in appendix IV.

Susan Fleming

Director, Physical Infrastructure
Appendix I: Objectives, Scope, and 

Methodology

Page 32 GAO-13-168 Pipeline Safety

The objectives of our review were to determine (1) the opportunities that 

exist to improve the ability of transmission pipeline operators to respond 

to incidents and (2) the advantages and disadvantages of installing 

automated valves in high-consequence areas and ways that the Pipeline 

and Hazardous Materials and Safety Administration (PHMSA) can assist 

operators in deciding whether to install valves in these areas.

To address our objectives, we reviewed regulations, National 

Transportation Safety Board (NTSB) incident reports, and PHMSA 

guidance and data on enforcement actions, pipeline operators, and 

incidents, related to onshore natural gas transmission and hazardous 

liquid pipelines. We also attended industry conferences and interviewed 

officials at PHMSA headquarters and regional offices (Eastern, 

Southwestern, and Western), state pipeline safety agencies, pipeline 

safety groups, and industry associations. Specifically, we interviewed 

officials from the American Gas Association, American Petroleum 

Institute, Arizona Office of Pipeline Safety, Association of Oil Pipelines, 

Interstate Natural Gas Association of America, National Association of 

Pipeline Safety Representatives, NTSB, Pipeline Research Council 

International, Public Utilities Commission of Ohio, and West Virginia 

Public Service Commission.

To address both objectives, we also conducted case studies on eight 

hazardous liquid and natural gas pipeline operators. We selected these 

operators based on our review of PHMSA data on the operators’ onshore 

pipeline mileage, product type and prior incidents, recommendations from 

industry associations and PHMSA, and to ensure geographic diversity. 

We selected six hazardous liquid and natural gas pipeline operators with 

a large amount of pipeline miles in high-consequence areas that also 

reported recent incidents (i.e., one or more incident(s) reported from 2007 

through 2011) with a range of characteristics, such as: affected a highconsequence area; resulted in an ignition/explosion; or involved an 

automated valve. We also selected one natural gas pipeline operator and 

one hazardous liquid pipeline operator with a small number of pipeline 

miles in high-consequence areas, to obtain the perspective of smaller 

pipeline operators.1 Specifically, we interviewed officials from:

 

1

According to 2010 PHMSA data, the eight operators we selected represented 19 percent 

of hazardous liquid and 10 percent of natural gas miles in high-consequence areas. There 

were 682 hazardous liquid and natural gas transmission pipeline operators with 98,013 

pipeline miles in high-consequence areas.

Appendix I: Objectives, Scope, and 

Methodology 
Appendix I: Objectives, Scope, and 

Methodology

Page 33 GAO-13-168 Pipeline Safety

• Belle Fourche Pipelines (Casper, Wyoming)—Hazardous Liquids;

• Buckeye Partners (Breinigsville, Pennsylvania)—Hazardous Liquids;

• Enterprise Products (Houston, Texas)—Hazardous Liquids and 

Natural Gas;

• Granite State Gas Transmission (Portsmouth, New Hampshire)—

Natural Gas;

• Kinder Morgan-Natural Gas Pipeline Company (Houston, Texas)—

Natural Gas;

• Phillips 66 (Houston, Texas)—Hazardous Liquids;

• Northwest Pipeline GP (Salt Lake City, Utah)—Natural Gas; and

• Williams-Transco (Houston, Texas)—Natural Gas.

To determine what opportunities exist to improve the ability of 

transmission pipeline operators to respond to incidents, we identified 

several factors that influence pipeline operators’ incident response 

capabilities. To do so, we discussed prior incidents, incident response 

times, and federal oversight of the pipeline industry with officials from 

PHMSA, state pipeline safety offices, industry associations, and safety 

groups. We also spoke with operators about their prior incidents and the 

factors that influenced their ability to respond. We also examined 2007 to

2011 PHMSA incident data, including data on total number of incidents, 

type of incident (leak or rupture), type of pipeline where the incident 

occurred, and the date and time when: an incident occurred; an operator 

identified the incident; operator resources (personnel and equipment) 

arrived on site; and an operator shut down a pipeline or facility. We 

assessed the reliability of these data through discussions with PHMSA 

officials and selected operators. We determined that data elements 

related to numbers of incidents, types of releases, and types of pipeline 

where incidents occurred were reliable for the purpose of providing 

context, but that data elements related to response time were not 

sufficiently reliable for the purpose of conducting a detailed analysis of 

relationships between response time and other factors. We also reviewed 

federal requirements, prior GAO reports, and industry and government 

performance standards related to emergency response within the pipeline 

industry.

To determine the advantages and disadvantages of installing automated 

valves in high-consequence areas and the ways that PHMSA can assist 

operators in deciding whether to install these valves, we identified the key 

factors that should be used in deciding whether to install automated 

valves in high-consequence areas. We used two categories of sources to 

identify the key factors:
Appendix I: Objectives, Scope, and 

Methodology

Page 34 GAO-13-168 Pipeline Safety

(1) Literature review. We conducted a literature review of previous 

research on pipeline incidents. Specifically, we used online 

research software to search through databases of scholarly and 

peer-reviewed materials—including articles, journals, reports, 

studies, and conferences dating back to 1995—which identified 

over 200 sources.

(2) Interviews with industry stakeholders. During our interviews with 

officials from industry associations and pipeline safety groups, we 

discussed the advantages and disadvantages of installing these 

valves.

To ensure that the literature review included just those documents that 

were relevant to our purpose, two analysts independently reviewed 

abstracts from the 200 sources identified to determine whether they were 

within the scope of our review. Each source had to meet specific criteria, 

including mentioning automated valves, pipeline incidents, and operator 

emergency response. We excluded sources that were overly technical for 

the purposes of our review. To ensure these analysts were making similar 

judgments, they separately examined a random sampling of each other’s 

sources. The analysts then added sources suggested by industry 

stakeholders during our interviews and reviewed them using the same 

criteria. After excluding documents that were not publicly available, one 

analyst reviewed these sources to identify advantages and disadvantages 

operators should consider when making decisions to install automated 

valves. A second analyst reviewed the analysis and performed a spot 

check on identified advantages and disadvantages. Specifically, the 

second analyst picked four of the sources at random to review and 

compared the advantages and disadvantages he identified to those of the 

first analyst. As part of our case studies, we discussed these advantages 

and disadvantages with operators. We also collected information from 

operators on their methods for deciding whether to install automated 

valves, as well as specific pipeline segments and valve locations where 

operators made such decisions (see app. II). We contacted vendors 

(manufacturers and installers) of automated valves to identify the range of 

costs for purchasing and installing these valves. We also discussed the 

regulations with officials from PHMSA headquarters and regional offices, 

state pipeline safety offices, and pipeline operators to determine what, if 

any, additional guidance would help operators apply the current 

regulations on installing automated valves.

We conducted this performance audit from March 2012 to January 2013 

in accordance with generally accepted government auditing standards. 
Appendix I: Objectives, Scope, and 

Methodology

Page 35 GAO-13-168 Pipeline Safety

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.
Appendix II: How Select Operators Determined 

Whether to Install Automated Valves

Page 36 GAO-13-168 Pipeline Safety

We conducted site visits to eight hazardous liquid and natural gas 

pipeline operators with different amounts of pipeline miles in or affecting 

high-consequence areas.1 Seven of the eight operators we visited told us 

they use approaches that consider both the advantages and 

disadvantages of installing automated valves on a case-by-case basis as 

opposed to other safety measures; the eighth operator stated that it 

follows a corporate strategy of installing automated valves in all highconsequence areas. A brief description of the approach used by each of 

the eight operators, based on our discussions with them, follows.

Pipeline operator: Belle Fourche

Product type: Hazardous liquid

Number of pipeline miles: 460 (total); 135 (could affect highconsequence areas)

Decision-making approach: The operator assesses each pipeline 

segment2 using spill-modeling software to determine the amount of 

product release and extent of damage that would occur in the event of an 

incident. The software considers flow rates, pressure, terrain, product 

type, and whether the segment is located over land or a waterway. 

Monetary costs are considered as part of the decision-making process,

including the cost of installing communications equipment and gaining 

access to the valve location when the operator does not own the right of 

way. The operator stated that installing a remote-control valve costs 

between $100,000 and $500,000. Automatic-shutoff valves are not 

considered as the operator believes an accidental closure could lead to 

pipeline ruptures.

 

1

Requirements for integrity management require hazardous liquid pipeline operators to 

determine whether an incident on their pipeline could affect a high-consequence area, 

while natural gas pipeline operators are required to determine whether their pipeline is in a 

high-consequence area. Regulations also define how to identify high-consequence areas 

for these two types of operators.

2

Pipeline segments are discrete sections of the pipeline system separated by valves that 

can stop the flow of product. The distance between valves is dictated in federal 

regulations. C.F.R. §§ 192.179, 195.260.

Appendix II: How Select Operators 

Determined Whether to Install Automated 

Valves
Appendix II: How Select Operators Determined 

Whether to Install Automated Valves

Page 37 GAO-13-168 Pipeline Safety

Results to date: According to Belle Fourche officials, this approach has 

not resulted in any decisions to install automated valves because the 

advantages have not outweighed the disadvantages on any of the 

pipeline segments assessed.3

Pipeline operator: Buckeye Partners

Product type: Hazardous liquid

Number of pipeline miles: 6,400 (total); 4,179 (could affect highconsequence areas)

Decision-making approach: The operator assesses each pipeline 

segment using spill-modeling software to determine the amount of 

product release and extent of damage that would occur in the event of an 

incident. The operator considers installation of an automated valve when 

this modeling shows such a valve would 1) reduce the size of the incident 

by 50 percent or more and 2) significantly reduce the consequences of an 

incident. The operator conducts additional analysis to determine the 

location where the automated valve would lead to the largest reduction in 

spill volume and overall consequences of an incident. Monetary costs are 

considered as part of the decision-making process, including costs for 

gaining access to pipeline when the operator does already not own the 

right of way. The operator stated that installing a remote-control valve 

costs between $35,000 and $325,000. Automatic-shutoff valves are 

considered, but not typically installed, as the operator believes an 

accidental closure could lead to a pipeline rupture.

Results to date: According to Buckeye Partners officials, this approach 

has resulted in additional analysis of the possible installation of 25 

remote-control valves along 75 pipeline segments assessed.

Pipeline operator: Phillips 66

Product type: Hazardous liquid

 

3

According to the operator, several automated valves have been installed independent 

from this decision-making approach.
Appendix II: How Select Operators Determined 

Whether to Install Automated Valves

Page 38 GAO-13-168 Pipeline Safety

Number of pipeline miles: 11,290 (total); 3,851 (could affect highconsequence areas)

Decision-making approach: The operator assesses every 100 feet of 

pipeline (which covers all pipeline segments) using spill-modeling 

software to determine the amount of product release and extent of 

damage that would occur in the event of a complete rupture. The operator 

also uses a relative consequence index for individual pipeline segments 

that considers the impact to high-consequence areas. Automated valve 

projects are further evaluated if 1) the potential drain volume is greater 

than 1,000 barrels, 2) the pipeline segment exceeds a certain threshold 

on the consequence index, or 3) the existing automated valves are 

greater than 7.5 miles apart. Monetary costs are considered as part of the 

decision-making process, including the cost of installing communications 

equipment, access to power, gaining access to the valve’s location when 

the operator does not own the right of way, and local construction costs. 

The operator stated that installing an automated valve costs between 

$250,000 and $500,000. Automatic-shutoff valves are not considered as 

the operator believes an accidental closure could lead to pipeline 

ruptures.

Results to date: According to the Phillips 66 officials, this approach has 

resulted in decisions to install 71 automated valves in the 508 highconsequence area locations assessed.

Pipeline operator: Enterprise Products

Product type: Hazardous liquid and natural gas

Number of pipeline miles: 23,012 (total); 8,783 (could affect or in highconsequence areas)

Decision-making approach: The operator assesses each pipeline 

segment using spill-modeling software to determine the amount of 

product release and extent of damage that would occur in the event of an 

incident. The software considers factors such as topography and the 

placement of existing valves. The operator also uses a risk algorithm to 

identify threats to individual pipeline segments. The operator told us that it 

does not have specific criteria for guiding decisions to install automated 

valves; rather, officials make judgment calls based on the results of spill 

modeling and the application of the risk algorithm. Monetary costs are 

considered as part of the decision-making process, including the cost of 
Appendix II: How Select Operators Determined 

Whether to Install Automated Valves

Page 39 GAO-13-168 Pipeline Safety

installing communications equipment and the amount of necessary 

infrastructure work. The operator stated that installing a remote-control

valve costs between $250,000 and $500,000. Pipelines carrying gas or 

highly volatile liquids—which are in gas form when released into the 

atmosphere—are excluded from consideration, according to the operator, 

because industry studies have shown that automated valves do not 

significantly improve incident outcomes for these product types.

Results to date: According to Enterprise Products officials, this approach 

has not resulted in any decisions to install automated valves because the 

advantages have not outweighed the disadvantages on any of the 

pipeline segments assessed.

Pipeline operator: Granite State Gas Transmission

Product type: Natural gas

Number of pipeline miles: 86 (total); 11 (high-consequence areas)

Decision-making approach: The operator assesses individual pipeline 

segments in high-consequence areas using risk analysis software that 

considers the operator’s response time to an incident, population in the 

area, and pipeline diameter, among other variables. Monetary costs are 

considered as part of the decision-making process, including the cost of 

installing communications equipment and costs to change or improve the 

existing leak detection system. The operator stated that installing an 

automated valve costs between $40,000 and $50,000. Automatic-shutoff 

valves are not considered, as officials believe that they could lead to 

unintended consequences, such as accidental closures.

Results to date: According to Granite State Gas Transmission officials, 

this approach has resulted in decisions to install remote-control valves in 

30 of the 30 locations assessed.

Pipeline operator: Kinder Morgan-Natural Gas Pipeline Company of 

America (NGPL)

Product type: Natural gas

Number of pipeline miles: 9,800 (total); 569 (high-consequence areas)
Appendix II: How Select Operators Determined 

Whether to Install Automated Valves

Page 40 GAO-13-168 Pipeline Safety

Decision-making approach: The operator follows a long-term corporate 

risk management strategy for NGPL, developed in the 1960s, that calls 

for installing automatic-shutoff valves across its pipeline system 

regardless of advantages and disadvantages for individual pipeline 

segments. The operators told us that automatic-shutoff valves, as 

opposed to remote-control valves, were chosen because they reduce the 

potential for human error when making decisions to close valves. Officials 

stated that the biggest concern of using automatic-shutoff valves is the 

potential for accidental closures, but they believe they have developed a 

procedure for managing the pressure sensing system that effectively 

adapts to pressure and flow change and minimizes or eliminates these 

types of closures. Monetary costs are not considered as part of the 

decision-making process. The operator stated that installing automaticshutoff valve on an existing manual valve costs between $48,000 and 

$100,000.

Results to date: According to Kinder Morgan officials, this approach has 

resulted in the installation of automated valves at 683 out of 832 locations 

across the pipeline system. Officials plan to automate the remaining 

valves over the next several years.

Pipeline operator: Northwest Pipeline GP4

Product type: Natural gas

Number of pipeline miles: 3,900 (total); 170 (high-consequence areas)

Decision-making approach: The operator uses a decision tree to 

assess individual pipeline segments based on several criteria, including 

the location of the valve (e.g., high-consequence area), diameter of the 

pipe, and the amount of time it takes for an operator to respond upon 

notification of an incident. The operator will install an automated valve in 

 

4

Williams Gas Pipeline is the parent company of two operators we visited: Northwest 

Pipeline GP and Williams Gas Pipeline-Transco. Northwest Pipeline GP is also referred to 

as WGP West. Williams Gas Pipeline-Transco is one of three pipeline systems that make 

up WGP East, which also includes Gulfstream Pipeline and Cardinal Pipeline.
Appendix II: How Select Operators Determined 

Whether to Install Automated Valves

Page 41 GAO-13-168 Pipeline Safety

any high-consequence, class 3, or class 4 areas5 on large diameter pipe 

(i.e., above 12 inches) where personnel cannot reach and close the valve 

in under an hour. Monetary costs are considered as part of the decisionmaking process for the purposes of determining the most cost-effective 

way to ensure the operator can respond within one hour to incidents in 

high-consequence areas. The operator stated that installing an 

automated valve costs between $37,000 and $240,000. Automatic-shutoff 

valves are not installed in areas where an accidental closure could lead to 

customers losing service (i.e., in places where there is a single line feed 

servicing the entire area) or where pressure fluctuations may 

inadvertently activate the valve.

Results to date: According to Northwest Pipeline GP officials, this 

approach has resulted in decisions to install automated valves at 59 of 

the 730 locations assessed.

Pipeline operator: Williams Gas Pipeline-Transco6

Product type: Natural gas

Number of pipeline miles: 11,000 (total); 1,192 (high-consequence 

areas)

Description of decision-making method: The operator uses a decision 

tree to assess individual pipeline segments based on several criteria, 

including the location of the valve (e.g., high-consequence area), 

diameter of the pipe, and the amount of time it takes for an operator to 

respond upon notification of an incident. The operator will install an 

automated valve in any high-consequence, class 3, or class 4 areas on 

 

5

The Pipeline and Hazardous Materials Administration regulates natural gas pipelines 

based on class locations. Class 3 includes any location with more than 46 buildings 

intended for human occupancy within 220 yards of a pipeline, or an area where the 

pipeline lies within 100 yards of either a building or a small, well-defined outside area 

(such as a playground) that is occupied by 20 or more persons at least 5 days a week for 

10 weeks in any 12-month period. Class 4 includes any location where unit buildings with 

four or more stories above ground are prevalent. See 49 CFR 192.5.

6

Williams Gas Pipeline is the parent company of two operators we visited: Northwest 

Pipeline GP and Williams Gas Pipeline-Transco. Northwest Pipeline GP is also referred to 

as WGP West. Williams Gas Pipeline Transco is one of three pipeline systems that make 

up WGP East, which also includes Gulfstream Pipeline and Cardinal Pipeline.
Appendix II: How Select Operators Determined 

Whether to Install Automated Valves

Page 42 GAO-13-168 Pipeline Safety

large diameter pipe (i.e., above 12 inches) where personnel cannot reach 

and close the valve in under an hour. Monetary costs are considered as 

part of the decision-making process for the purposes of determining the 

most cost-effective way to ensure the operator can respond within one 

hour to incidents in high-consequence areas. The operator stated that 

installing an automated valve costs between $75,000 and $500,000. 

Automatic-shutoff valves are not installed in areas where an accidental 

closure could lead to customers losing service (i.e., in places where there 

is a single line feed servicing the entire area) or where pressure 

fluctuations may inadvertently activate the valve.

Results to date: According to Williams Gas Pipeline-Transco officials, 

this approach has resulted in decisions to install automated valves at 56 

of the 2,461 locations assessed.
Appendix III: Automated Valve Costs

Page 43 GAO-13-168 Pipeline Safety

The eight operators we spoke with provided a range of cost estimates for 

installing automated valves—from as low as $35,000 to as high as 

$500,000 depending on the location and size of the pipeline, and the type 

of equipment being installed, among other things.1 While both hazardous 

liquid and natural gas transmission pipeline operators estimated a similar 

cost range from about $35,000 to $500,000, hazardous liquid pipeline 

operators tended to estimate higher costs. Specifically, two of the three 

operators that exclusively transport hazardous liquids estimated that the 

minimum costs of installing an automated valve was $100,000 or higher 

and the maximum was $500,000. In contrast, pipeline operators that 

exclusively transport natural gas all estimated that the minimum cost was 

$75,000 or lower and three of the four operators estimated that maximum 

costs would be $240,000 or lower.

We also spoke with five equipment vendors and six contractors that install 

valves to gather additional perspective on the cost of purchasing and 

installing automated valve equipment.2 According to estimates provided 

by these businesses, the combined equipment and labor costs range 

between $40,000 and $380,000. Specifically, equipment costs range from 

$10,000 to $75,000 while labor costs range from $30,000 to $315,000. 

(See table 3.) Vendors stated that the cost of installing an automated 

valve depends primarily on the functionality of the equipment (for 

example, additional controls would increase the cost), while contractors 

stated that these costs depend on the diameter and location of the 

pipeline. Vendors and contractors had varying opinions on whether the 

costs were greater to install an automated valve on hazardous liquid or 

natural gas pipeline.

 

1

Several hazardous liquid operators indicated that the cost of installing an automated 

valve could be as high as $1 million under specific circumstances, but stated that these 

high costs are unusual.

2

One pipeline contractor we spoke with had not yet installed an automated valve and did 

not did not provide cost estimates for doing so. Instead the contractor stated that the labor 

costs of installing a manual valve on an existing pipeline would be between $60,000 and 

$80,000.

Appendix III: Automated Valve Costs
Appendix III: Automated Valve Costs

Page 44 GAO-13-168 Pipeline Safety

Table 3: Range of Equipment and Labor Costs, According to Pipeline Vendors and Contractors

Equipment vendor Range of equipment costs Contractor Range of labor costs

#1 $10,000 – $75,000 #1 $30,000 – $150,000

#2 $15,000 – $30,000 #2 $35,000 – $175,000

#3 $15,500 – $43,000 #3 $40,000 – $150,000

#4 $30,500 – $43,500 #4 $100,000 – $200,000

#5 $32,000 – $46,000 #5 $120,000 – $315,000

Average $20,600 – $47,500 Average $65,000 – $198,000

Source: GAO presentation of vendor and contractor information.
Appendix IV: GAO Contact and Staff 

Acknowledgments

Page 45 GAO-13-168 Pipeline Safety

Susan Fleming, (202) 512-3824 or flemings@gao.gov. 

In addition to the contact above, Sara Vermillion (Assistant Director), 

Sarah Arnett, Melissa Bodeau, Russ Burnett, Matthew Cook, Colin Fallon, 

Robert Heilman, David Hooper, Mary Koenen, Grant Mallie, Josh 

Ormond, Daniel Paepke, Anne Stevens, and Adam Yu made key 

contributions to this report.

Appendix IV: GAO Contact and Staff 

Acknowledgments 

GAO Contact

Staff 

Acknowledgments 

(541091)
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