a

GAO

United States Government Accountability Office

Report to Congressional Committees

September 2006 NATURAL GAS 

PIPELINE SAFETY

Integrity Management 

Benefits Public Safety, 

but Consistency of 

Performance 

Measures Should Be 

Improved

GAO-06-946
What GAO Found

United States Government Accountability Office

Why GAO Did This Study

Highlights

Accountability Integrity Reliability

September 2006

GAS PIPELINE SAFETY

Integrity Management Benefits Public 

Safety, but Consistency of Performance 

Measures Should Be Improved 

Highlights of GAO-06-946, a report to 

congressional committees 

The Pipeline Safety Improvement

Act of 2002 established a risk-based

program for gas transmission 

pipelines—the integrity

management program. The 

program requires operators of 

natural and other gas transmission 

pipelines to identify “high 

consequence areas” where pipeline 

incidents would most severely 

affect public safety, such as those 

occurring in highly populated or 

frequented areas. Operators must

assess pipelines in these areas for 

safety risks and repair or replace

any defective segments. Operators 

must also submit data on 

performance measures to the 

Pipeline and Hazardous Materials 

Safety Administration (PHMSA). 

The 2002 act also directed GAO to

assess this program’s effects on 

public safety. Accordingly, we

examined (1) the effect on public

safety of the integrity management 

program and (2) PHMSA and state 

pipeline agencies’ plans to oversee 

operators’ implementation of 

program requirements. To fulfill 

these objectives, GAO interviewed 

51 gas pipeline operators and 

surveyed all state pipeline

agencies. 

What GAO Recommends

GAO recommends revisions to

PHMSA’s performance measures to 

improve the agency’s ability to 

determine the impact of the 

program over time. The 

Department of Transportation 

generally agreed with the report’s

findings and recommendations.

The gas integrity management program is designed to benefit public safety 

by supplementing existing safety requirements with risk-based management 

principles that focus on safety risks in high consequence areas, such as

highly populated or frequented areas. Early indications show that the 

condition of transmission pipelines is improving as operators complete 

assessments and related repairs of their pipelines. For example, as of 

December 31, 2005, operators had assessed 33 percent of pipelines in high 

consequence areas and completed over 2,000 repairs. Furthermore, up to 68

percent of the population living near gas transmission pipelines is expected 

to benefit from improved pipeline safety because they live in highly 

populated areas. Representatives from the pipeline industry, safety advocacy 

groups, and state pipeline safety agencies generally agree that integrity 

management improves public safety, but operators noted that the program 

can be costly to implement and cited concerns with implementing the 

program, such as meeting the documentation requirements. PHMSA’s 

performance measures should demonstrate the impact of the program over 

time. However, we are recommending revisions to improve the measures. 

For example, adjusting the incident reporting requirement to account for 

changes in the price of natural gas would allow PHMSA to more accurately 

track trends in pipeline incidents. 

PHMSA and states plan to use a variety of inspection tools to oversee 

operators’ implementation of integrity management requirements and expect 

to complete the first round of inspections no later than 2009. To assist in 

conducting these inspections, PHMSA has developed a range of tools, 

including guidance documents and training courses for inspectors. Overall, 

state agencies have found these tools to be useful, although some states have 

found it difficult to schedule the required training courses and have some 

concerns about the adequacy of their staffing. To address these concerns, 

PHMSA is taking steps to make it easier for state inspectors to attend the 

training and supports providing additional funding to states. Initial results 

from 20 federal inspections and 117 state inspections show that operators 

are making good progress in assessing pipelines and making repairs, but 

they generally need to better document their decisions and processes. 

Integrity Management Process for Gas Transmission Pipelines

Source: GAO.

Report this information to PHMSA. 

Evaluate pipelines periodically for 

new high consequence areas.

Identify 

pipeline 

threats and 

perform risk assessments.

Identify high

consequence 

areas.

Conduct 

baseline assessments, assessing 

pipelines with 

the greatest 

risk first.

Repair or 

replace any 

defective 

pipeline 

segments.

Perform 

preventive 

and 

mitigative 

measures.

Reassess

pipelines as

required.

Are

pipelines

located

in high

consequence areas?

Report performance measures to PHMSA semiannually.

Document all decisions and processes.

Yes

No

www.gao.gov/cgi-bin/getrpt?GAO-06-946.

To view the full product, including the scope 

and methodology, click on the link above. 

For more information, contact Katherine 

Siggerud at (202) 512-2834 or 

siggerudk@gao.gov. 
Page i GAO-06-946 Natural Gas Pipeline Safety

Contents

Letter 1

Results in Brief 2

Background 4

Gas Integrity Management Benefits Public Safety, although 

Operators Have Some Implementation Concerns, and 

Performance Measures Could Be Improved 7

PHMSA and State Pipeline Agencies Plan to Use Inspection Tools 

Developed by PHMSA to Complete the Initial Round of 

Inspections by 2009 16

Conclusions 23

Recommendations for Executive Action 23

Agency Comments and Our Evaluation 23

Appendixes

Appendix I: Scope and Methodology 26

Appendix II: Results of State Pipeline Agency Survey 30

Appendix III: Contact and Staff Acknowledgments 37

Table Table 1: Integrity Management Performance Measures Reported by 

Operators as of December 31, 2005 13

Figures Figure 1: Gas Pipeline System 4

Figure 2: Integrity Management Process for Gas Transmission 

Pipelines 7

Figure 3: Highly Populated Areas within 660 Feet of a Natural Gas 

Transmission Pipeline 10

Abbreviations

DOT Department of Transportation

IMP gas integrity management program

OPS Office of Pipeline Safety

PHMSA Pipeline and Hazardous Materials Safety Administration 
Contents

Page ii GAO-06-946 Natural Gas Pipeline Safety

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

United States. It may be reproduced and distributed in its entirety without further 

permission from GAO. However, because this work may contain copyrighted images or 

other material, permission from the copyright holder may be necessary if you wish to 

reproduce this material separately.
Page 1 GAO-06-946 Natural Gas Pipeline Safety

United States Government Accountability Office

Washington, D.C. 20548

A

September 8, 2006 Letr

Congressional Committees:

While pipelines are a relatively safe mode for transporting natural gas, on 

average, about three people have died and about eight people have been 

injured annually over the past 10 years in natural gas transmission pipeline 

incidents. To enhance the safety of pipelines and strengthen existing 

federal pipeline safety oversight by the Pipeline and Hazardous Materials 

Safety Administration (PHMSA), Congress passed the Pipeline Safety 

Improvement Act of 2002. A key element of the act is a risk-based 

program—termed “integrity management”—for gas transmission pipelines. 

The integrity management program requires gas transmission pipeline 

operators (operators) to develop programs to assess and mitigate safety 

threats to sections of their pipeline systems where leaks or ruptures would 

have the greatest impact on public safety. These “high consequence areas” 

are generally in highly populated or frequently used areas, such as parks. 

Operators must identify their pipelines in high consequence areas and then 

systematically assess these pipelines for safety risks, such as internal 

corrosion, and repair or replace any defective pipeline sections. Operators 

must also take additional measures, such as computer monitoring of the 

pipeline and additional training on response procedures, to prevent and 

mitigate the consequences of a pipeline failure in high consequence areas.

The Pipeline Safety Improvement Act of 2002 directed us to assess the 

effects on public safety stemming from the integrity management program 

for gas transmission pipelines. Accordingly, we examined (1) the effect on 

public safety of the integrity management requirements for gas 

transmission pipelines and (2) the plans of PHMSA and state pipeline safety 

agencies to oversee operators’ implementation of integrity management 

requirements.

To carry out this work, we reviewed laws, regulations, and PHMSA 

guidance and inspection reports related to the gas integrity management 

program. We interviewed agency officials responsible for developing and 

administering the gas integrity management program, gas pipeline trade 

associations, pipeline safety advocacy groups, state pipeline agencies, and
Page 2 GAO-06-946 Natural Gas Pipeline Safety

51 gas transmission pipeline operators.1 The information that we obtained 

from the operators is not generalizable to all operators. We also surveyed 

the 47 state pipeline agencies with responsibility for overseeing gas 

transmission pipeline operators’ implementation of integrity management.2

As part of our work, we assessed the internal controls and the reliability of 

the data needed for this engagement and determined that the data were 

sufficiently reliable for our purposes. We performed our work between 

August 2005 and July 2006 in accordance with generally accepted 

government auditing standards. (See app. I for additional details on our 

scope and methodology and app. II for a copy of our survey sent to state 

pipeline agencies and the aggregated results.) 

Results in Brief The gas integrity management program is benefiting public safety by 

supplementing existing safety requirements with risk-based management 

principles that focus on safety risks in highly populated or frequented 

areas, referred to as high consequence areas. While the program is still 

being implemented, the condition of transmission pipelines is improving as 

operators complete their first round of pipeline assessments and make 

repairs. As a result of integrity management, 33 percent of the identified 

pipelines in high consequence areas had been assessed and over 2,000 

repairs had been completed, as of December 31, 2005. Furthermore, we 

estimate that up to 68 percent of the population that lives close to natural 

gas transmission pipelines is located in highly populated areas and is 

expected to receive additional protection, as a result of improved pipeline 

safety, as operators complete their baseline assessments by December 

2012. Gas pipeline industry, state pipeline agency, and safety advocate 

representatives generally agree that the program enhances public safety, 

citing operators’ improved knowledge of the risks to their pipeline systems 

that stems from systematic assessments as the primary benefit of the 

program. However, operators noted that integrity management is not 

without its costs; most operators we contacted have hired additional staff 

or contractors as a result of integrity management requirements. 

1

Although the gas integrity management program applies to natural, toxic, and corrosive 

gases, the overwhelming majority of gas pipelines in the United States carry natural gas. 

Therefore, our work focused on natural gas pipelines.

2

Pipeline agencies in 46 states and the District of Columbia have this responsibility and, for 

the purposes of this report, we treat the agency in the District of Columbia as a state 

pipeline agency. Two states do not have state pipeline agencies, and two states do not have 

any intrastate gas transmission operators.
Page 3 GAO-06-946 Natural Gas Pipeline Safety

Furthermore, operators cited concerns about implementing the program, 

such as meeting the program’s documentation requirements. Despite these 

concerns, operators are making good progress in assessing and repairing 

their pipeline systems, as demonstrated by the semiannual performance 

measures that operators report to PHMSA. However, how the performance 

measures are reported may hinder PHMSA’s ability to determine the 

program’s impact over time. For example, incident reporting requirements 

do not include an adjustment for changes in the price of natural gas, even 

though the value of gas released is a key factor in determining whether an 

incident should be reported to PHMSA. Therefore, a change in the number 

of incidents reported over time may reflect a change in the price of natural 

gas rather than a change in the safety of the pipeline system. We are making 

recommendations to improve the performance measures, thereby 

improving PHMSA’s ability to assess the effectiveness of the integrity 

management program. 

PHMSA and states plan to use a variety of inspection tools to oversee 

operators’ implementation of integrity management requirements and 

expect to complete the first round of inspections no later than 2009. 

PHMSA developed a range of tools to help prepare and assist federal and 

state inspectors in conducting integrity management inspections, including 

guidance documents for evaluating operators’ integrity management 

programs, training courses to provide inspectors with a knowledge of 

technical issues, and communication mechanisms. Overall, state agencies 

have found these tools to be useful, although several states have found it 

difficult to schedule the required training courses, and many have 

expressed concerns about the adequacy of their staffing. To address these 

concerns, PHMSA has taken steps to make it easier for state inspectors to 

attend the training, and it supports providing additional funding to states 

that could be used for staffing needs. PHMSA and states have begun 

inspections. According to PHMSA and state officials, initial results from 20 

of about 100 federal inspections and 117 of about 670 state inspections that 

have been completed or started show that operators are doing well in 

assessing their pipelines and making repairs; but, in general, operators 

need to better document their policies and procedures. Based on these 

initial inspection results, PHMSA and states generally did not find many 

issues that warranted enforcement actions to date.

In commenting on a draft of this report, the Department of Transportation 

generally agreed with the report’s findings and recommendations and cited 

actions the department has already initiated or plans to take to implement 

the recommendations.
Page 4 GAO-06-946 Natural Gas Pipeline Safety

Background Within the United States, there are about 295,000 miles of gas transmission 

pipelines, which are part of larger gas pipeline systems that transport 

natural gas from producing wells to users. (See fig. 1.) Gas gathering lines 

collect natural gas from production facilities and transport it to 

transmission pipelines. In turn, gas transmission pipelines transport gas 

products to processing plants, and then on to communities and largevolume users, such as power plants. Gas distribution pipelines continue to 

transport natural gas from transmission pipelines to residential, 

commercial, and industrial customers. 

Figure 1: Gas Pipeline System 

PHMSA, within the Department of Transportation (DOT), administers the 

national regulatory program to ensure the safe transportation of natural gas 

and hazardous liquid by pipeline.3

 PHMSA carries out its mission through 

regulation, national consensus standards, research, education, inspections, 

and enforcement when safety problems are found. The agency employs 

about 165 staff in its pipeline safety program, about half of whom are 

pipeline inspectors who inspect gas and hazardous liquid pipelines under 

integrity management and other more traditional compliance programs. In 

general, PHMSA retains full responsibility for inspecting and enforcing 

Gathering

pipelines

thering

pipelines

Transmission pipeline on pipeline

Natural gas

producing wells

Processing

plant

Transmission pipeline

City gate

Large volume

customer

Large volume

customer

Distribution

pipelines

Regulator 

Meter 

Source: Pipeline and Hazardous Materials Safety Administration.

Compressor

station

Underground

storage

Compressor

station

Liquified natural

gas plant 

3

In addition to the gas gathering and transmission pipelines, PHMSA oversees the safety of 

nearly 1.9 million miles of gas distribution pipelines and 160,000 miles of hazardous liquid 

pipelines.
Page 5 GAO-06-946 Natural Gas Pipeline Safety

regulations on interstate pipelines that cross state boundaries, but it has 

arrangements with 48 states, the District of Columbia, and Puerto Rico to 

assist with overseeing intrastate pipelines. PHMSA allows state agencies 

the flexibility to design their programs to best meet their needs, although it 

conducts an annual audit of each state’s inspection program. States are 

currently authorized to receive reimbursement of up to 50 percent of the 

costs of their pipeline safety programs from PHMSA. 

Traditionally, PHMSA has performed its oversight role using uniform, 

minimum safety standards that all pipeline operators must meet.4

 For gas 

transmission pipeline operators, these standards are based on the “class 

location” of the pipeline. A pipeline’s class location—based on factors such 

as population within 660 feet of the pipeline—determines the thickness of 

the pipe required and the pressure at which it can operate. Recognizing that 

pipeline operators face different risks, depending on such factors as 

location and the products they carry, PHMSA began exploring the concept 

of a risk-based approach to pipeline safety in the mid-1990s.5

 The 

Accountable Pipeline Safety and Partnership Act of 1996 included 

provisions for DOT to establish a demonstration program to test such a 

risk-based approach.6

 As a result, PHMSA established the Risk 

Management Demonstration Program, which went beyond the agency’s 

traditional regulatory approach by allowing individual operators to identify 

and focus on the risks unique to their pipelines. According to a PHMSA 

official, the demonstration project identified the need for operators to 

better understand the condition of their pipelines, including the risks and 

threats to their pipelines. The agency subsequently moved forward with a 

new regulatory approach—termed integrity management—to supplement 

the existing uniform, minimum regulations. Integrity management created 

a systematic process to managing the safety of the pipeline and is designed 

to provide for continual improvement. PHMSA established requirements 

for integrity management for hazardous liquid pipeline operators with 500 

or more miles of pipelines in December 2000 and for operators with less 

than 500 miles in January 2002. In 2000, PHMSA was also exploring issues 

4

Minimum safety standards for natural gas pipelines are found in 49 C.F.R. part 192; and 

safety standards for hazardous liquid pipelines are found in 49 C.F.R. part 195.

5

Within PHMSA, the Office of Pipeline Safety administers the national regulatory program to 

assure the safety of pipelines. Prior to March 2005, PHMSA was known as the Research and 

Special Programs Administration.

6

P.L. No. 104-304, 110 Stat. 3793 (1996).
Page 6 GAO-06-946 Natural Gas Pipeline Safety

related to integrity management for gas transmission pipelines, including 

collaboration with the pipeline industry to develop consensus standards for 

gas integrity management, which were subsequently incorporated into the 

regulations. These consensus standards cover issues such as establishing 

and conducting integrity management programs and actions operators 

must take to assess the extent of corrosion in their pipelines.

In 2003, PHMSA issued integrity management regulations for all operators 

of gas transmission pipelines.7

 As shown in figure 2, under these 

regulations, operators must identify and assess segments of their pipelines 

that are located in “high consequence areas,” which are highly populated or 

frequently used areas, such as parks, where pipeline leaks or ruptures 

could have the greatest impact on public safety. Operators are required to 

collect and integrate data from their entire pipeline system—such as maps, 

information on corrosion protection, exposed pipeline, and threats from 

excavation or other third-party damage—to identify the threats to their 

high consequence areas. Pipeline threats include corrosion; welding 

defects and failures; third-party damage (e.g., from excavation equipment); 

land movement; and incorrect operation. Once operators have identified 

the threats, they must perform a risk assessment to determine which 

pipeline segments are most susceptible to those threats. Starting with the 

pipelines that are most susceptible, operators must then assess the 

condition of their pipelines—referred to as baseline assessments—on half 

of their pipeline mileage in high consequence areas by December 2007 and 

the remainder by December 2012. Using the results of the assessments, 

operators must repair or replace any defective sections of pipeline. 

Operators are also required to perform preventive and mitigative measures, 

such as installing computerized monitoring and leak detection systems.8

 In 

addition, operators are required to reassess their pipelines in high 

consequence areas for corrosion problems at least every 7 years and for all 

safety threats at least every 10, 15, or 20 years, depending on the condition 

of the pipelines and the stress under which the pipeline segments are 

operated. Operators must also document processes to ensure actions for 

managing pipeline integrity are applied consistently and that the results are 

repeatable across the company. For example, operators are required to 

7

PHMSA is currently developing integrity management regulations for gas distribution 

pipelines and expects to issue these regulations in 2007.

8

The measures are in addition to those already required in 49 C.F.R. part 192 and are specific 

to the threats that were identified for each pipeline segment.
Page 7 GAO-06-946 Natural Gas Pipeline Safety

have written processes for management of change, quality assurance, and 

communication. 

Figure 2: Integrity Management Process for Gas Transmission Pipelines 

Gas Integrity 

Management Benefits 

Public Safety, although 

Operators Have Some 

Implementation 

Concerns, and 

Performance Measures 

Could Be Improved

The gas integrity management program is designed to improve pipeline 

safety by supplementing existing standard safety requirements with riskbased management principles, including performance measures to monitor 

progress. For the first time, all operators are required to systematically 

assess the condition of their pipelines in high consequence areas and make 

identified repairs. As of December 31, 2005, operators report having 

assessed about 33 percent of their pipelines in high consequence areas and 

completed over 2,000 repairs. In addition, we estimate that up to 68 percent 

of people living along natural gas transmission pipelines are located in 

highly populated areas and are expected to receive additional protection as 

operators continue to assess and repair their pipelines in these areas. 

Furthermore, the gas pipeline industry, state pipeline agencies, safety 

advocate representatives, and operators with whom we spoke generally 

agree that the program benefits public safety. While early indicators show 

that integrity management benefits public safety, some operators noted 

that the program is not without its costs. Operators also expressed 

uncertainty about the program’s documentation requirements. Despite 

these concerns, operators are making good progress in implementing 

integrity management, as demonstrated by the performance measures that 

operators report semiannually to PHMSA. However, these performance 

measures could be improved to better enable PHMSA to identify the 

program’s impact on public safety.

Source: GAO.

Action stage

Decision point

Report this information to PHMSA. 

Evaluate pipelines periodically for 

new high consequence areas.

Identify 

pipeline 

threats and 

perform risk assessments.

Identify high

consequence 

areas.

Conduct 

baseline assessments, assessing 

pipelines with 

the greatest 

risk first.

Repair or 

replace 

any 

defective 

pipeline 

segments.

Perform 

preventive 

and 

mitigative 

measures.

Reassess

pipelines

as required.

Are

pipelines

located

in high consequence areas?

Report performance measures to PHMSA semiannually.

Document all decisions and processes.

Yes

No
Page 8 GAO-06-946 Natural Gas Pipeline Safety

Integrity Management 

Offers Additional Protection 

Over Minimum Safety 

Standards

Prior to the integrity management program, there were, and still are, 

minimum safety standards for the design, construction, operation, and 

maintenance of all gas transmission pipelines that provide the public with a 

basic level of protection from pipeline failures. For example, all operators 

are required to have a system to protect their pipelines from corrosion. 

Federal or state inspectors use a “checklist” approach to determine 

whether operators have such a system and that it is operating 

appropriately.9

 However, the minimum safety standards do not account for 

the differences in the kinds of threats and degrees of risk that pipelines 

face. In addition, inspections of the operators verify that the standards are 

being followed, but do not evaluate the effectiveness of the protective 

measures put into place, such as the corrosion protection system, because 

the standards do not require operators to assess the integrity of their 

pipelines. Consequently, some pipelines have operated for 40 or more years 

without being assessed. However, 33 of 51 operators (about 65 percent) 

told us they had assessed the integrity of some of their pipelines prior to 

the integrity management regulations. 

The gas integrity management program goes beyond existing minimum 

safety standards by using risk-based management principles to provide an 

additional level of safety to the public where the impact of pipeline leaks, 

failures, or incidents could be the greatest. Risk-based management has 

several key characteristics that help to ensure safety—it (1) uses 

information to identify and assess risks; (2) prioritizes risks so that 

resources may be allocated to address higher risks first; (3) promotes the 

use of regulations, policies, and procedures to provide consistency in 

decision making; and (4) monitors performance. The gas integrity 

management program embodies each of these characteristics. It requires 

operators to integrate information from different sources (both internal 

and external) to identify the risks specific to their pipelines and then use 

data from the assessment of their pipelines to make necessary repairs and 

take preventive measures. To prioritize risks for resource allocation, 

integrity management focuses on high consequence areas and requires 

operators to assess the riskiest segments of their pipelines first. Five 

operators told us that the requirements of integrity management has helped 

focus resources, and one said it has even helped to justify the need for 

resources that would otherwise have been difficult to obtain. To provide a 

9

According to guidance which PHMSA provided to the states, state inspectors may use an 

inspection form or checklist that references the federal and state regulations.
Page 9 GAO-06-946 Natural Gas Pipeline Safety

level of consistency in how tasks are performed and decisions are made, 

the integrity management program requires operators to document their 

policies and procedures. In addition, PHMSA developed inspection 

protocols and “frequently asked questions” to help define the agency’s 

expectations for operators and help ensure consistency in inspections. 

According to PHMSA, having procedures, roles, and responsibilities clearly 

defined is crucial for operators to ensure continual and consistent 

management for safety. Finally, integrity management requires operators to 

monitor their progress by reassessing their pipelines at specified intervals. 

Operators must also report to PHMSA semiannually on specific 

performance measures related to integrity management. These measures 

include the total mileage of pipelines and the mileage of pipelines assessed 

in high consequence areas, as well as the number of repairs made and the 

number of incidents, leaks, and failures identified in these areas. 

We estimate that this risk-based approach should offer additional safety 

benefits for up to 68 percent of the population living near gas transmission 

pipelines; this estimate corresponds with PHMSA’s estimate of two-thirds 

of the population. Even though the integrity management program applies 

to only pipelines in high consequence areas, which account for about 7 

percent of all transmission pipeline miles, the population living along 

pipelines tends to be clustered in these areas. Using Census data, we 

estimated that up to 68 percent of the people who live near (within 660 

feet) natural gas transmission pipelines are located in highly populated 

areas and thus should be afforded additional protection as a result of 

integrity management. (See fig. 3.) 
Page 10 GAO-06-946 Natural Gas Pipeline Safety

Figure 3: Highly Populated Areas within 660 Feet of a Natural Gas Transmission Pipeline

While operators do not report the location of their high consequence areas, 

population is a key component to identifying these areas. Using Census 

data to identify the population living along pipelines, we estimated that 

about 22,000 miles of transmission pipelines could be considered as being 

in highly populated areas, which is similar to the 20,294 miles of pipelines 

reported by operators as being in high consequence areas. Therefore, our 

estimate of the highly populated areas is a reasonable approximation of the 

high consequence areas. 

Sources: the U.S. Census Bureau and PHMSA (data); GAO (graphic). 
Page 11 GAO-06-946 Natural Gas Pipeline Safety

Early Indicators Show That 

Integrity Management Is 

Beneficial, Despite Some 

Operators’ Concerns about 

Implementation 

Although the integrity management program is still being implemented, a 

number of representatives from pipeline industry organizations, state 

pipeline agencies, safety advocate groups, and operators we contacted 

agree that integrity management benefits public safety because it requires 

all operators to systematically assess their pipelines to gain a 

comprehensive knowledge about the risks to their pipeline systems. In 

addition, operators must repair problems or anomalies identified in their 

pipelines. As of December 31, 2005, 33 percent of the identified pipelines in 

high consequence areas had been assessed, and over 2,000 repairs had been 

completed. 

Six of the 51 operators we interviewed also pointed to the benefit of 

improved communications within their companies. Investigations of 

pipeline incidents have shown that, in some cases, an operator possessed 

information that could have prevented an incident but did not share the 

information with employees who needed it most. The integrity 

management program requires operators to integrate pipeline data from 

various sources within the company to identify threats to the pipelines, 

leading to more interaction among different departments within pipeline 

companies. 

While all operators we contacted generally believe integrity management is 

beneficial, the program is not without its costs. For example, over half of 

the operators with whom we spoke said that they have hired additional 

staff or contractors as a result of integrity management requirements. 

Furthermore, one operator told us that, although it assessed its pipeline 

before the gas integrity management program was enacted, the operator 

now spends about 5,000 to 10,000 more hours per year on assessments 

because it must integrate data from multiple sources—some of which are 

formatted differently—requiring that the operator make all data consistent 

before using it. Another operator told us that implementation of the 

program was costly because its gas transmission pipelines are located 

under pavement. These pipelines could not be assessed using tools that run 

through pipelines, so the operator had to excavate, visually assess, and 

repave over the pipelines, which is costly. A third operator estimated that it 

had spent between $8.5 million and $10 million on developing its integrity 

management program and related systems. This operator also estimated 

that its annual operating costs had increased by $16.5 million to $21.5 

million to comply with the integrity management regulations, even though 

it had an aggressive inspection and testing program prior to those 

regulations. 
Page 12 GAO-06-946 Natural Gas Pipeline Safety

Operators also cited other concerns about implementing their integrity 

management programs. One of the more frequently identified concerns by 

the operators, cited by 19 of the 51 operators we contacted (37 percent), 

was related to the level of documentation needed to support their gas 

integrity management programs. PHMSA requires operators to develop an 

integrity management program and provides a broad framework for the 

elements that should be included in the program. The regulations provide 

operators the flexibility to develop their programs to best suit their 

companies’ needs, but each operator must develop and document specific 

policies and procedures to demonstrate its commitment to compliance 

with and implementation of the integrity management program. Operators 

may use existing policies and procedures if they meet the integrity 

management requirements. In addition, operators must document any 

integrity management related decisions to demonstrate that they 

understand the risks to their pipelines and are systematically managing 

their pipelines for these risks. For example, an operator must document 

how it identified the threats to its pipeline and assessed the risks, how 

these risks will be managed, who was involved in these decisions and their 

qualifications, and the data they used. While the operators we contacted 

generally agreed with the need to document their policies and procedures, 

some said that the detailed documentation required for every decision is 

very time consuming and does not contribute to the safety of pipeline 

operations. In addition, a few operators expressed concern that they will 

not know if they have sufficient documentation until their program has 

been inspected. Initial inspections of operators by PHMSA and state 

pipeline agencies have confirmed that some operators are experiencing 

difficulty with documentation but generally are doing well with 

assessments and repairs. According to PHMSA and state officials, as 

operators continue to develop and implement their integrity management 

programs and as they are provided feedback during inspections, the 

documentation issues identified during these initial inspections should be 

resolved. 

Another concern raised by a majority of the operators is the requirement to 

reassess their pipelines for corrosion problems at least every 7 years. We 

recently reported that while reassessments are useful, the 7-year 

requirement appears to be conservative.10

10GAO, Natural Gas Pipeline Safety: Risk-based Standards Should Allow Operators to 

Better Tailor Reassessments to Pipeline Threats, GAO-06-945 (Washington, D.C.: Sept. 8, 

2006). 
Page 13 GAO-06-946 Natural Gas Pipeline Safety

Performance Measures 

Should Show Impact of 

Integrity Management Over 

Time, but Could Be 

Improved

Operators report to PHMSA semiannually on several performance 

measures that show the progress operators have made in implementing 

integrity management and, over time, should demonstrate the impact of 

integrity management on safety. Table 1 lists the performance measures 

and shows the progress operators reported as of December 31, 2005.

Table 1: Integrity Management Performance Measures Reported by Operators as of 

December 31, 2005

Source: PHMSA.

a

A leak is an unintentional escape of gas from a pipeline that does not result in an injury, death, or 

$50,000 in property damage. 

b

Failure is a general term used to imply that a part in service has become completely inoperable; is still 

operable but is incapable of satisfactorily performing its intended function; or has deteriorated 

seriously, to the point that it has become unreliable or unsafe for continued use.

c

An incident is defined as an event that involves a release of gas from a pipeline and (1) a death or 

personal injury necessitating in-patient hospitalization or (2) estimated property damage, including 

cost of gas lost, of $50,000 or more, or an event that is significant, in the judgment of the operator.

d

An immediate repair must be made when specific conditions are identified related to the strength of a 

pipeline, a dent with an indication of metal loss or cracking, or an anomaly judged to require immediate 

action. 

e

Scheduled repairs must be made within 1 year and generally include conditions where a dent has 

been identified but there is no indication of metal loss. 

Total mileage reported and assessed: As a result of technology that many 

operators are using to assess their pipelines, operators are assessing a 

much greater portion of total pipeline mileage than that which is located in 

high consequence areas. In addition, they are making repairs to these 

pipelines. Of the 51 operators we contacted, 36 (71 percent) are using inPipeline performance measures for gas transmission 

pipelines Statistics

Total miles of pipelines reported 296,138

Total miles of pipelines assessed 50,441

Gas transmission pipelines within high consequence 

areas:

Total miles reported 20,294

Total miles assessed 6,707

Leaksa 221

Failuresb 28

Incidentsc 19

Immediate repairs completedd 340

Scheduled repairs completede 1,981
Page 14 GAO-06-946 Natural Gas Pipeline Safety

line assessment tools that run inside the pipelines to assess the integrity of 

some or all pipelines within high consequence areas. These tools must be 

inserted and removed from the pipelines at designated locations that often 

run through areas other than high consequence areas. Consequently, 

operators reported having assessed about 44,000 miles of pipelines located 

outside high consequence areas, which represents about 15 percent of all 

gas transmission pipelines. Operators that use the in-line assessment tools 

told us that they assess the entire distance of pipeline between the 

insertion and retrieval points because, in doing so, they gather additional 

insights into the condition of their pipeline. While operators are not 

required to report to PHMSA the results of the assessments in areas outside 

of the high consequence areas, a number of operators with whom we spoke 

said that they plan to make or have made repairs identified through the 

assessments, regardless of where they are identified, thereby expanding 

the benefits of integrity management beyond the high consequence areas.

High consequence mileage reported and assessed: As of December 2005, 

operators had assessed about 6,700 miles of their 20,000 miles of pipeline 

—or about 33 percent—located in high consequence areas. This progress 

indicates that operators are well on their way to meeting the requirement to 

conduct baseline assessments on 50 percent of their pipelines in these 

areas by December 2007. Operators must then complete the rest of their 

baseline assessments by December 2012. Most of the operators with whom 

we spoke (48 of 51) said they had no major concerns about their ability to 

complete baseline assessments, as required. 

Incidents, leaks, and failures: While pipelines are considered a relatively 

safe mode of transporting gas, integrity management is designed to 

improve pipeline safety and should lead to a reduction in the number of 

incidents, leaks, and failures over time. PHMSA and the pipeline industry 

have generally used the number of incidents, related fatalities, and injuries 

as a measure for determining the safety of pipelines. Since the inception of 

integrity management, 19 of the 305 incidents reported for all pipelines in 

fiscal years 2004 and 2005 occurred in high consequence areas. The 

majority of the incidents reported in high consequence areas—10 of the 19 

incidents—were caused by third-party damage. Leaks have traditionally 

been reported by operators in their annual reports, but this information is 

not generally aggregated nationwide, so it is not possible to determine how 

leaks in high consequence areas compare with those in other areas. 

Failures were not typically reported to PHMSA prior to integrity 

management; therefore, it is not possible to compare the number of failures 

in high consequence areas with those in other areas. As PHMSA collects 
Page 15 GAO-06-946 Natural Gas Pipeline Safety

information on incidents, leaks, and failures over time, the agency will be 

able to identify trends and make these comparisons.

Immediate and scheduled repairs completed: In addition to assessing 

pipelines, operators are also making progress in fulfilling the requirement 

to repair problems found on pipelines in high consequence areas. In the 2 

years that operators have reported the results of integrity management, 

they have completed 340 repairs that were immediately required and 

another 1,981 scheduled repairs in high consequence areas. While it is not 

possible to determine the number of needed repairs that would have been 

identified without integrity management, it is clear that the requirement to 

routinely assess pipelines enables operators to identify problems that may 

otherwise go undetected. For example, one operator told us that it had 

complied with all the minimum safety standards on its pipeline, and the 

pipeline appeared to be in good condition. The operator then assessed the 

condition of a segment of the pipeline under its integrity management 

program and found a serious problem, causing it to shut down the pipeline 

for immediate repair. 

While the integrity management performance measures should allow 

PHMSA to measure the impact of the program, the measures related to 

incidents, leaks, and failures could be improved to better allow for optimal 

comparison of performance over time and make them more consistent with 

other pipeline safety measures. For example, incident reporting 

requirements do not include an adjustment for changes in the price of 

natural gas, even though the value of gas released is a key factor in 

determining whether an incident must be reported to PHMSA. A reportable 

incident is defined, in part, as when the estimated property damage, 

including the cost of gas lost, meets a threshold of $50,000. Since this 

reporting threshold has not been adjusted over time, as the price of gas has 

increased, it is difficult to use the number of incidents over time as an 

indicator of pipeline safety. For many years the price of gas was relatively 

stable. However, since 1999, natural gas prices have increased by about 179 

percent, while the threshold for reporting an incident has not changed. As a 

result, smaller releases of gas from a pipeline meet the definition of an 

incident and artificially inflate the number of pipeline incidents. For 

example, in 1999, a release of about 16,100 thousand cubic feet of gas 

would have triggered the incident reporting requirement, compared with 

only about 5,800 thousand cubic feet of gas in 2005. In 2002, PHMSA began 

collecting information on the value of gas released during an incident. 

Adjusting the 183 gas transmission pipeline incidents that occurred in 2005 

to reflect the price of gas in 1999 would have resulted in about 27 fewer 
Page 16 GAO-06-946 Natural Gas Pipeline Safety

incidents. PHMSA officials recognize the advantages of changing the 

reporting requirements to adjust for the changing price of gas or to be 

based on the volume of gas rather than its value, but PHMSA has not yet 

initiated a rule to change the reporting requirement. 

In addition, the usefulness of the performance measure data is limited in 

part by inconsistencies in the reporting of causes of incidents and leaks in 

high consequence areas compared with the rest of the pipeline system. For 

example, to report a leak within a high consequence area, operators may 

choose from three separate corrosion causes: internal corrosion, external 

corrosion, or stress-corrosion cracking.11 In contrast, to report a leak 

outside of a high consequence area, operators use one overall category for 

corrosion. Without consistent reporting of causes, it is difficult to compare 

the reasons for incidents and leaks in high consequence areas with those 

along the rest of the pipeline system. We are making recommendations to 

improve the consistency of the integrity management performance 

measures. 

PHMSA and State 

Pipeline Agencies Plan 

to Use Inspection Tools 

Developed by PHMSA 

to Complete the Initial 

Round of Inspections 

by 2009 

PHMSA has developed various tools to help prepare and assist federal and 

state inspectors in conducting inspections. These inspection tools include 

guidance documents for evaluating operators’ integrity management 

programs, training courses to provide inspectors with the knowledge of 

technical issues, and communication mechanisms. Overall, most state 

pipeline agency officials told us that these tools are useful; although about 

half of the state officials with whom we spoke have found it difficult to 

schedule the required training courses, and the majority have some 

concerns about the adequacy of their staffing. To address these concerns, 

PHMSA has taken steps to make it easier for state inspectors to attend 

training and supports a proposal from states to provide additional funding 

that could be used for staffing needs. PHMSA and states have begun 

inspections and expect to complete the first round of inspections no later 

than 2009. PHMSA has completed 20 of about 100 inspections, and states 

have begun or completed 117 of about 670 inspections, as of June 2006 and 

January 2006, respectively. PHMSA and state officials reported that the 

initial results from these inspections show that operators are doing well in 

11Internal corrosion occurs on the inside of the pipe due to a chemical attack from 

something in the pipe, external corrosion occurs on the outside of the pipe due to 

environmental conditions, and stress-corrosion cracking results from stress that causes 

clusters of cracks to develop and grow until the pipe fails.
Page 17 GAO-06-946 Natural Gas Pipeline Safety

implementing the assessment and repair requirements of the integrity 

management program, but they need to improve documentation of their 

program’s processes.

PHMSA Has Developed 

Tools to Prepare Inspectors 

for Integrity Management 

Inspections

In collaboration with state pipeline agencies, PHMSA developed guidance 

documents—inspection protocols, supplemental guidance, and “frequently 

asked questions”—to assist federal and state inspectors in evaluating 

operators’ integrity management programs. The inspection protocols 

provide a roadmap for conducting inspections. The protocols walk the 

inspectors through the integrity management requirements in the 

regulations to help inspectors verify that an operator’s program complies 

with the regulations. These inspection protocols are available to the public, 

and many operators with whom we spoke said they had reviewed the 

protocols when developing their programs. To supplement the inspection 

protocols, PHMSA has provided inspectors with additional guidance on the 

types of questions to ask operators, documents to review, and key elements 

to consider in evaluating operators’ programs. However, this supplemental 

guidance has not been provided to operators: it is intended to be 

suggestions for inspectors rather than requirements for operators because 

PHSMA expects programs to differ, given that each operator is unique. In 

addition, PHMSA posts “frequently asked questions” and corresponding 

answers to its Web site. This tool further clarifies the regulations and 

PHMSA’s expectations for what should be included in operators’ plans. 

PHMSA also developed a series of required training courses to inform 

federal and state inspectors of technical topics relevant to the integrity 

management regulations. The 10 training courses—4 classroom and 6 

computer-based courses—take about 20 days to complete and address the 

integrity management inspection protocols as well as specific threats to the 

pipelines (such as stress-corrosion cracking, and internal and external 

corrosion) and different assessment techniques (such as in-line assessment 

and direct assessment).12 While most (13 of 21) state officials with whom 

we spoke consider the required training to be important, about half noted 

that it is difficult for inspectors to schedule the classroom training on 

inspection protocols. PHMSA has taken steps to help state inspectors 

12In-line assessment involves running a specialized tool through a pipeline to detect and 

record problems, such as corrosion and damage. Direct assessment is a structured process 

to integrate information on the physical characteristics and operating history of a pipeline 

with the results of an examination to determine the integrity of the pipeline.
Page 18 GAO-06-946 Natural Gas Pipeline Safety

attend this training, such as offering the course in each of the five PHMSA 

regional offices in 2005 and providing travel funds for two inspectors from 

each state to attend. In addition, PHMSA maintains flexibility in scheduling 

the course and schedules classes once it receives enough requests. As a 

result, according to PHMSA records, at least one inspector from 46 of 47 

states has attended the required training. The remaining state agency 

reported that it had confirmed that the gas transmission pipeline operators 

in its state do not have any pipelines in high consequence areas. 

Another tool that PHMSA and state pipeline agencies may use is on-the-job 

training. PHMSA invites state inspectors to participate in PHMSA-led 

inspections of interstate operators that allow state inspectors to learn how 

PHMSA conducts inspections, to ask questions, and to gain experience in 

using the protocols. The majority (12 of 21) of state officials with whom we 

spoke indicated that their inspectors have, or will have, participated in 

PHMSA-led inspections before conducting their own inspections. As time 

permits, PHMSA inspectors also will attend state-led inspections to provide 

guidance and answer questions. 

Finally, PHMSA has implemented several mechanisms—such as Web sites, 

conference calls, and meetings—to communicate with federal and state 

inspectors. For example, PHMSA created a restricted Web site where 

federal and state inspectors may obtain guidance documents, access 

information pertaining to inspections, pose questions on the integrity 

management program, and communicate with other inspectors. Through 

this tool, inspectors may learn from other inspectors’ experiences by 

reviewing documentation of completed inspections that are posted. All 

completed federal inspections will be posted, and 28 states reported that 

they intend to post the results of their inspections as well. PHMSA also 

holds conference calls and periodic meetings with federal and state 

inspectors to discuss their experiences and identify opportunities to 

improve the inspection program. In addition, PHMSA keeps state pipeline 

agencies informed about gas integrity management through regular 

updates through the National Association of Pipeline Safety 

Representatives. These updates include Web site links and status reports 

on issues such as training classes, upcoming inspections, and work groups. 

Although communication between PHMSA and states has been 

problematic in the past, the majority of states (41 of 47) reported that
Page 19 GAO-06-946 Natural Gas Pipeline Safety

PHMSA’s efforts to improve communication and guidance pertaining to gas 

integrity management have been useful.13

First Round of Inspections 

Is Expected to Be 

Completed by 2009 and 

Initial Inspections Show 

Operators Are Making Good 

Progress in Conducting 

Assessments

PHMSA and state pipeline agencies plan to conduct more than 700 gas 

integrity management inspections, with the majority expected to be 

completed no later than 2009.14 PHMSA anticipates conducting a total of 

about 100 inspections of interstate gas transmission pipeline operators, of 

which about 80 are expected to have pipelines in high consequence areas. 

The 47 state pipeline agencies anticipate conducting a total of about 670 

inspections of intrastate gas transmission operators, including those with 

and without pipelines in high consequence areas.15 The majority of states 

(41 of 47) reported that they will each conduct fewer than 20 inspections, 

although one state reported that it will conduct as many as 256 inspections. 

Just as operators continually assess their pipelines, PHMSA and states plan 

to inspect operators’ programs on a regular basis. PHMSA plans to conduct 

inspections of operators’ programs at least once every 3 or 4 years, and 

more than half of the state agencies plan to conduct these inspections at 

least once every year or 2. 

To conduct these inspections, PHMSA currently has 22 trained inspectors, 

9 of which are assigned exclusively to conducting integrity management 

inspections. In 2002, we reported that PHMSA’s efforts to identify the 

resources and expertise needed to implement its integrity management 

approach were hampered by the lack of an up-to-date assessment of 

current and future staffing and training needs.16 In response to our 

recommendation to develop a workforce plan, PHMSA drafted a workforce 

13GAO, Pipeline Safety and Security: Improved Workforce Planning and Communication 

Needed, GAO-02-785 (Washington, D.C.: Aug. 26, 2002). We surveyed the 47 state pipeline 

agencies about their opinions on integrity management, their plans for overseeing operator 

implementation, and communication with PHMSA.

14PHMSA and states do not know the exact number of integrity management inspections 

they will have to conduct because multiple operators may be included under one integrity 

management program. 

15Inspections of operators without identified high consequence areas will be abbreviated 

and will ensure that the operators correctly made this determination and have a process to 

regularly reevaluate their system to identify any potential new areas that are subject to 

integrity management. 

16GAO, Pipeline Safety and Security: Improved Workforce Planning and Communication 

Needed, GAO-02-785 (Washington, D.C.: Aug. 26, 2002).
Page 20 GAO-06-946 Natural Gas Pipeline Safety

plan in March 2005 that considers the essential elements of such a plan. For 

example, the plan identifies trends likely to impact the number and types of 

field staff needed and identifies competencies needed to meet PHMSA’s 

strategic goals. In addition, the plan includes an examination of how its 

workforce should be deployed across the organization and suggests 

assigning staff to regions based on regional workload and need. 

State officials with whom we spoke reported additional staffing concerns 

as a result of integrity management inspections. State pipeline agencies 

generally employ between one and five inspectors to perform these 

inspections, although they may not be dedicated to integrity management. 

The Pipeline Safety and Improvement Act of 2002 increased the workload 

of state pipeline agencies by establishing three new inspection 

requirements for integrity management, operator qualifications and public 

awareness programs.17 However, state staffing and funding levels were 

generally not increased to fulfill these additional responsibilities. States are 

handling the increased workload in various ways, such as combining 

inspections, modifying the frequency of inspections, or focusing efforts on 

completing one new inspection at a time. For example, a few states focused 

on completing operator qualifications inspections before starting integrity 

management inspections. In addition, 11 state officials said that it is 

difficult to hire qualified staff, such as engineers, who are needed for the 

technical nature of the integrity management inspections. According to two 

state officials, state agencies are losing trained inspectors because the state 

salaries are typically lower than those paid by operators. To help states 

deal with increased workload and hiring issues, the National Association of 

Pipeline Safety Representatives has recommended that PHMSA be allowed 

to reimburse state pipeline agencies up to 80 percent of their inspection 

program costs—up from the current allowance of up to 50 percent of 

program costs. PHMSA supports this increase, and such an increase is 

included as part of the proposed Pipeline Safety Improvement Act of 2006 

(H.R. 5678 and H.R. 5782).18

17In addition to integrity management programs, all pipeline operators are required to have 

operator qualification programs to ensure that the individuals who perform certain safety 

tasks are qualified to conduct such tasks and public education programs on pipeline safety 

issues, such as one-call notification, the hazards of unintended releases, and the steps to 

take if there is a release and the procedure for reporting a release. 

18GAO, Gas Pipeline Safety: Views on Proposed Legislation to Reauthorize Pipeline Safety 

Provisions, GAO-06-1027T (Washington, D.C.: Aug. 4, 2006).
Page 21 GAO-06-946 Natural Gas Pipeline Safety

PHMSA and about half of the state pipeline agencies have begun 

conducting inspections of operators’ implementation of the integrity 

management requirements. PHMSA and states generally started initial 

integrity management inspections in 2005.19 As of June 2006, PHMSA 

reported having completed 20 of about 100 inspections, encompassing 

about 7,063 of the 10,039 miles in high consequence areas that PHMSA is 

responsible for inspecting. About half of the state pipeline agencies 

reported that they had started or completed 117 of about 670 inspections as 

of January 31, 2006. In response to our survey, most of the remaining states 

reported that they anticipate beginning inspections in 2006. PHMSA 

selected the operators for initial inspections based on their history of 

working well with PHMSA and their expected level of program 

development to allow PHMSA inspectors to gain experience with its 

inspection protocols and process. After the first nine inspections, PHMSA 

met with inspectors to discuss the process and has made some revisions to 

the protocols based on inspectors’ recommendations. PHMSA’s current and 

future inspection schedule is determined by using a risk-ranking system 

that considers factors such as an operator’s compliance history and 

pipeline mileage. Using this system should result in inspections of 

operators with a higher potential of having an incident or problem prior to 

those operators with a lower potential. According to PHMSA’s “Guidelines 

for States Participating in the Pipeline Safety Program,” states should use 

the date of the last inspection and operating history to prioritize operators 

for inspections. Seven state officials told us they initially inspected all 

operators’ programs to ensure they had a program and had identified their 

high consequence areas, and that a more detailed inspection would be done 

in the future. 

According to a PHMSA official and state officials, initial integrity 

management inspections show that operators are generally experiencing 

few problems with assessing and repairing pipelines, although some 

operators are having trouble documenting their processes and procedures 

and thus are failing to get adequate credit for their efforts. PHMSA 

considers documentation important for ensuring that an operator is 

appropriately implementing the program, that the operator is committed to 

continued implementation, and that the program is being consistently 

implemented throughout an operator’s organization. It is also important to 

document the processes and procedures so that knowledge of the process 

19Texas began inspections in 2001 for the state integrity management regulations that were 

in place prior to the federal integrity management regulations.
Page 22 GAO-06-946 Natural Gas Pipeline Safety

is not lost as staff changes occur. According to PHMSA, the documentation 

should include identifying the person involved in the decision or task, 

information needed and steps taken to make the decision or complete a 

task, and the results. Two state officials said that the operators in their 

states with few transmission pipeline miles were making efforts to comply 

but that they were struggling with implementing integrity management 

requirements. For example, the operator of a paper mill that also owns and 

operates about 8 miles of gas transmission pipeline to transport gas to its 

production facility stated that it is struggling to understand and comply 

with integrity management requirements. According to PHMSA and state 

officials, as operators continue developing and implementing their integrity 

management programs, and as they are provided feedback during 

inspections, the issues identified during these initial inspections should be 

resolved. 

PHMSA is continuing to determine the appropriate enforcement actions, if 

any, as a result of its initial inspections and will consider all available 

enforcement tools, including civil penalties. As of June 30, 2006, six 

enforcement actions have been processed but no fines have been assessed. 

Four operators have been issued a Notice of Amendment, which indicates a 

need to improve their written processes and procedures. In addition, two of 

these operators have also received a Notice of Probable Violation and 

Proposed Compliance Order for potentially failing to fully comply with the 

risk analysis requirement in the rule. According to a PHMSA official, the 

enforcement actions processed to date are proposed actions and will 

become final after the operators have had an opportunity for a hearing. 

PHMSA has developed a process that provides consistent standards for the 

inspectors and regional directors to use in determining when an 

enforcement action is warranted. The process lays out criteria to determine 

the severity of each issue identified during the inspection, whether 

enforcement action is appropriate and, if so, what type of action to take. As 

part of their agreements with PHMSA, most states are responsible for 

taking appropriate enforcement actions as a result of their inspections. 

Most state officials said that issues identified during their initial integrity 

management inspections have not warranted enforcement actions. 

However, one state official with whom we spoke issued a notice of 

violation to an operator that had not developed an integrity management 

plan. The operator, with about 11 miles of gas transmission pipelines, told 

the state that it was unaware of the requirement to develop an integrity 

management program. The state official told us that, after the inspection, 

the operator immediately began developing a program, and the state 

inspector is to revisit this operator within 6 months. 
Page 23 GAO-06-946 Natural Gas Pipeline Safety

Conclusions The gas integrity management program has made a promising start. The 

program’s risk-based approach is supported by industry, state pipeline 

agencies, safety advocates, and operators. Although the national 

transmission pipeline system is extensive, much of the population that is 

potentially affected by a pipeline event is concentrated in highly populated 

areas, which will be provided additional protection through the program. 

Thus far, operators are successfully implementing the critical assessment 

and repair requirements, and their documentation concerns should be 

resolved as operators gain experience with the program and receive 

feedback during inspections. While the progress in implementing the 

program to date is encouraging, PHMSA and state oversight will be critical 

to ensure that operators continue to effectively implement integrity 

management. As the program matures, PHMSA’s performance measures 

should allow the agency to quantitatively demonstrate the program’s 

impact on the safety of pipelines. However, relatively minor changes in how 

some of the measures are reported could help improve their usefulness and 

PHMSA’s ability to analyze and demonstrate the program’s impact over 

time. 

Recommendations for 

Executive Action

To improve the consistency and usefulness of the integrity management 

performance measures, we are recommending that the Secretary of 

Transportation direct the Administrator for the Pipeline and Hazardous 

Materials Safety Administration to take the following two actions: 

• revise the definition of a reportable incident to consider changes in the 

price of natural gas and

• establish consistent categories of causes for incidents and leaks on all 

gas pipeline reports.

Agency Comments and 

Our Evaluation

We provided a draft of this report to DOT for review and comment. We 

received oral comments from DOT officials, including the Assistant 

Administrator and Chief Safety Officer of PHMSA. The officials generally 

agreed with the report’s findings and recommendations. They agreed with 

the need to revise the definition of a reportable gas transmission pipeline 

incident, noting that doing so provides a more realistic and consistent basis 

for reporting. PHMSA has already begun informal discussions with various 

parties on this issue and expects to initiate the rule making necessary to 

change the definition of a reportable gas incident soon. The officials also 
Page 24 GAO-06-946 Natural Gas Pipeline Safety

agreed with the recommendation to have consistent categories of causes 

for incidents and leaks for all gas pipeline reports. PHMSA is evaluating 

several alternatives to reconcile the differences in the categories and 

expects to initiate action to implement this recommendation.

We are sending copies of this report to congressional committees and 

subcommittees with responsibility for transportation safety issues; the 

Secretary of Transportation; the Administrator, PHMSA; the Assistant 

Administrator and Chief Safety Officer, PHMSA; and the Director, Office of 

Management and Budget. We will also make copies available to others 

upon request. This report will be available at no charge on the GAO Web 

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

If you have any questions about this report, please contact me at 

siggerudk@gao.gov or (202) 512-2834. Contact points for our offices of 

Congressional Relations and Public Affairs may be found on the last page 

of this report. Staff who made key contributions to this report are listed in 

appendix III.

Katherine A. Siggerud

Director, Physical Infrastructure Issues
Page 25 GAO-06-946 Natural Gas Pipeline Safety

Congressional Committees

The Honorable Ted Stevens

Chairman

The Honorable Daniel K. Inouye

Co-Chairman

Committee on Commerce, Science

and Transportation

United States Senate

The Honorable Don Young

Chairman

The Honorable James L. Oberstar

Ranking Democratic Member

Committee on Transportation

and Infrastructure

House of Representatives

The Honorable Joe Barton

Chairman

The Honorable John D. Dingell

Ranking Minority Member

Committee on Energy and Commerce

House of Representatives
Page 26 GAO-06-946 Natural Gas Pipeline Safety

Appendix I

Scope and Methodology AAppenednxidexiIs

The Pipeline Safety Improvement Act of 2002 directed GAO to assess the 

effects on public safety stemming from the gas transmission pipeline 

integrity management program. Accordingly, the objectives of our report 

were to examine (1) the effect on public safety of the gas transmission 

pipeline integrity management program and (2) the plans of the Pipeline 

and Hazardous Materials Safety Administration (PHMSA) and state 

pipeline safety agencies to oversee gas transmission pipeline operators’ 

implementation of integrity management requirements. To address these 

objectives, we reviewed laws, regulations, performance measure data, and 

PHMSA guidance and inspection reports related to the gas integrity 

management program. We also interviewed PHMSA officials and 

representatives from gas pipeline trade associations, pipeline safety 

advocacy groups, state pipeline agencies, and gas transmission pipeline 

operators. In addition, we reviewed prior GAO reports related to pipeline 

safety.

To determine the effect that the gas integrity management program 

requirements have had on public safety, we analyzed how those 

requirements compare with minimum safety requirements to understand 

what additional requirements operators were subject to as a result of 

integrity management. We discussed with PHMSA officials how the 

regulations were designed and developed to improve public safety. Since 

the integrity management requirements apply to a relatively small 

percentage of all transmission pipeline miles—about 7 percent—we 

estimated the percentage of the population living along pipelines that 

should receive additional protection as a result of integrity management 

because they are located in highly populated areas. We used Census data to 

estimate the percentage of the population that lives within 660 feet of a 

transmission pipeline that are located in urban areas, which would be 

considered highly populated areas. We used Census data to identify highly 

populated areas because the specific locations that operators have 

identified as high consequence areas were not readily available. Operators 

have identified a total of 20,294 miles of gas transmission pipelines in high 

consequence areas, and we have likewise identified a total of about 22,000 

miles of pipelines in highly populated areas. Therefore, our estimate of 

pipelines in highly populated areas is a reasonable approximation of the 

pipelines in high consequence areas. 

To identify and understand the benefits and challenges the operators face 

in developing and implementing their integrity management programs, we 

contacted 51 gas transmission pipeline operators to discuss their 

experiences and views on the program. We selected a range of operators 
Appendix I

Scope and Methodology

Page 27 GAO-06-946 Natural Gas Pipeline Safety

with either large or small numbers of transmission pipeline miles since this 

could indicate the level of resources a particular operator would have to 

draw from to develop its integrity management program. We also selected 

operators based on a mixture of interstate and intrastate operators and 

considered the proportion of pipeline miles that each operator had in high 

consequence areas in our selection process. The information that we 

obtained from these operators is not generalizable to all gas transmission 

pipeline operators. We also discussed the integrity management program 

and its requirements with gas pipeline trade associations, pipeline safety 

advocacy groups, and state pipeline agencies to obtain their opinions on 

the benefits, challenges, and performance measures of the program. 

In addition, we analyzed the integrity management performance measure 

data reported by operators to PHMSA. We assessed the internal controls 

and the reliability of the data elements needed for this engagement and 

determined that they were sufficiently reliable for our purposes. We 

compared the reporting requirements for integrity management 

performance measures with other pipeline reported data. Given the early 

stages of implementation of the integrity management program, we 

determined that there was not enough comparable historical data to 

conduct a trend analysis to quantify the impact of the program to date. 

To determine PHMSA’s plans to oversee operators’ implementation of the 

integrity management program, we spoke with PHMSA officials about the 

inspection tools it developed to understand the purpose of the tools, their 

development, information that both federal and state inspectors receive 

about them, and plans for continual evaluation and improvement of the 

inspection program. We also reviewed the integrity management 

regulations, inspection protocols, supplemental guidance, frequently asked 

questions, and other guidance documents that inspectors may use to 

conduct integrity management inspections. While we compared the 

inspection protocols with the gas integrity management regulations to 

ensure that the protocols are aligned with the regulations, we did not 

evaluate the adequacy of these documents. We reviewed PHMSA 

requirements for both integrity management and core training, the 

schedule of training classes, and attendance records of state inspectors 

who have attended training on the inspection protocols. We also reviewed 

PHMSA’s schedule of inspections and documentation on how the agency 

prioritizes operators for inspections. In addition, we reviewed PHMSA’s 

workforce plan dated March 2005 to understand the agency’s efforts to 

identify the resources and expertise needed for integrity management.
Appendix I

Scope and Methodology

Page 28 GAO-06-946 Natural Gas Pipeline Safety

To understand the plans of state pipeline agencies to oversee operators’ 

implementation of integrity management requirements, we surveyed the 46 

state pipeline agencies and the District of Columbia pipeline agency that 

have responsibility for conducting gas integrity management inspections.1

We pretested the survey with three states prior to deployment. The survey 

covered state plans for inspections, resources and challenges, and 

communication with PHMSA. All 46 state agencies and the District of 

Columbia responded to our survey. (See app. II for a copy of the survey and 

aggregated results.) We then selected 15 states to contact to gain additional 

information on challenges the states face as a result of integrity 

management, benefits of the program to the pipeline industry, results of 

inspections started or completed, performance measures, and 

communication with PHMSA. We considered the following factors when 

selecting states to contact: geographic dispersion, whether inspections had 

been started or completed as of January 31, 2006, and whether states 

reported facing staffing and/or training challenges to a great or very great 

extent. In addition, we contacted three states prior to developing the 

survey. In total, we spoke with officials from 21 state pipeline agencies. 

These state agencies started or completed 103 of the 117 inspections 

started or completed, as of January 31, 2006. However, the information 

obtained from these conversations is not generalizable to all state pipeline 

agencies. We also reviewed documents from the National Association of 

Pipeline Safety Representatives to better understand the role of state 

pipeline agencies in overseeing operators. We also reviewed PHMSA’s 

guidance for state pipeline programs but did not evaluate PHMSA’s 

oversight of state pipeline programs. 

To understand the extent to which operators were complying with the 

integrity management requirements, we reviewed reports from 10 PHMSA 

inspections and 10 inspections from two states. Our review of the 

inspection reports was for illustrative purposes, and the results of our 

review cannot be generalized to all operators. We also spoke with PHMSA 

officials about their enforcement program and enforcement actions to date, 

and we reviewed regulations and PHMSA guidance on what enforcement 

actions may be taken and how PHMSA determines the appropriate action 

to take as a result of gas integrity management inspections. Since states 

1

We initially sent the survey to pipeline agencies in 48 states, the District of Columbia and 

Puerto Rico, however, we excluded two states (Connecticut and Rhode Island) and Puerto 

Rico since they did not have any intrastate gas transmission pipeline operators and 

therefore, have no responsibility for conducting these inspections. Alaska and Hawaii do not 

have state pipeline agencies, so the survey was not sent to them.
Appendix I

Scope and Methodology

Page 29 GAO-06-946 Natural Gas Pipeline Safety

were not required to develop a separate enforcement plan for gas integrity 

management and most state officials with whom we spoke had not taken 

any enforcement actions, we did not review state enforcement programs.
Page 30 GAO-06-946 Natural Gas Pipeline Safety

Appendix II

Results of State Pipeline Agency Survey ApendxiI

.com United States Government Accountability Office 

Survey of State Pipeline Agencies:

Gas Integrity Management Program Inspections

Introduction

The U.S. Government Accountability Office (GAO), an independent congressional agency, was required by the 

Pipeline Safety Improvement Act of 2002 (PL 107-355), to assess and evaluate the effects on public safety of the 

requirements for the implementation of gas transmission pipeline integrity management programs (IMP). As part 

of our work, GAO is reviewing how the Office of Pipeline Safety (OPS) within the Pipeline and Hazardous 

Materials Safety Administration plans to ensure that pipeline operators are complying with the IMP regulations. 

Given state pipeline agencies’ role in inspecting intrastate pipeline operators, we would like to understand the

extent to which states will be inspecting operators’ implementation of IMP. The following survey is intended to 

help us understand state plans for conducting IMP inspections, including the development of an inspection program

and resources required to conduct inspections. GAO is not auditing state inspection programs in any way.

Instructions for Completing This Questionnaire

This questionnaire can be filled out using MS-Word and returned via Email, or if you prefer, you may print the

questionnaire and complete it by hand. If you complete it by hand, you can return your survey via fax or mail.

If you are completing the survey in MS-Word, follow these instructions: 

x Please use your mouse to navigate by clicking on the field or check box you wish to answer.

x To select a check box or button, simply click on the center of the box.

x To change or deselect a check box response, simply click on the check box and the ‘X’ will disappear.

x To answer a question that requires that you write a comment, click on the answer box ____ and begin typing.

These boxes are highlighted in yellow. The box will expand to accommodate your answer. 

To assist us, we ask that you complete and return this survey by Friday, March 3, 2006.

To return by Email: Once the survey is completed, save this file to your computer desktop or hard drive and 

attach the file as part of your Email message to FrevertH@gao.gov or EdelsteinM@gao.gov.

To return by fax: Print the survey, complete it by hand, and fax it to: 202-512-4852. Please fax to the attention of 

Heather Frevert or Maria Edelstein.

To return by mail: Print the survey, complete it by hand, and mail it to: 

Heather Frevert or Maria Edelstein 

GAO

441 G Street, NW, Room 2T23B

Washington, DC 20548

If you have any questions about the contents of this questionnaire, please contact:

Heather Frevert Maria Edelstein

Phone: (202) 512-4203 OR Phone: (202) 512-6449

e-mail: FrevertH@gao.gov e-mail: EdelsteinM@gao.gov

 1
Appendix II

Results of State Pipeline Agency Survey

Page 31 GAO-06-946 Natural Gas Pipeline Safety

Respondent Information 

Please provide the following information for the individual coordinating the completion of this survey so that 

we may contact them to clarify any responses, or obtain additional information, if necessary.

0 Name:

Title:

Agency:

Telephone Number: ( ) - , Ext:

E-mail Address: @

Before completing the survey, please note the following: 

x Unless otherwise indicated, all responses should be made about your program at the state level. 

x There is space for your comments at the end of the survey.

x We recognize that it is early in the IMP implementation process, and that your program may change, as well as 

your opinions about the process. We ask that you answer these survey questions as they pertain to your current 

program status and your opinions as of today.

Integrity Management Program Regulations 

1. How many gas transmission pipeline operators do you currently have oversight responsibility 

for? No. of Operators Frequency

Operators 1-20 39

 21-50 6

 over 50 2

2. How many gas integrity management program (IMP) plans do you expect to have oversight 

responsibility for, given that multiple operators may follow the same IMP plan?

No. of IMPs Frequency

Plans 1-20 41

 21-50 3

over 50 2 (Note: No response = 1)

 2
Appendix II

Results of State Pipeline Agency Survey

Page 32 GAO-06-946 Natural Gas Pipeline Safety

3. Does your state have its own gas IMP regulations that are separate from the federal IMP

regulations?

No (46)

Yes (1) Æ 3a. If yes, briefly explain how your regulations are different than federal IMP 

regulations.

4. To what extent do you expect that gas IMP requirements will protect public safety? 

Very great extent ....................... (3) 

Great extent ............................... (10)

Moderate extent......................... (16)

Some extent ............................... (8) 

Little or no extent ..................... (0) 

Don’t know................................ (9) (Note: No response = 1)

5. In measuring the effectiveness of the gas transmission integrity management regulations, do you 

currently collect any performance measures that are above and beyond what the federal gas IMP 

rules require?

No (45)

Yes (2) 

6. In your opinion, are additional federal performance measures needed to measure the effectiveness

of the gas transmission integrity management regulations? 

No (17)

Yes (4) 

Undecided (25) (Note: No response = 1)

 3
Appendix II

Results of State Pipeline Agency Survey

Page 33 GAO-06-946 Natural Gas Pipeline Safety

Gas Integrity Management Program Inspections 

7. Will you follow the Office of Pipeline Safety’s (OPS) inspection protocols when conducting gas 

IMP inspections?

Yes, with no changes to the protocol ....................... (43) Æ SKIP TO QUESTION #9

Yes, but with some changes to the protocol............. ( 3) Æ SKIP TO QUESTION #9

No, we will not follow the OPS protocols................ ( 0) (Note: No response = 1)

8. If you will not follow the OPS protocols when conducting inspections, will you use inspection 

protocols that your state developed?

No n.a. (0 responses to “No, we will not follow . . .”, above) 

Yes n.a. (0 responses to “No, we will not follow . . .”, above) 

9. Has your state started inspections of gas IMP plans? 

 (23) No Æ SKIP TO QUESTION #10 

(23) Yes

a. On approximately what date did you start the inspections? 

 / (MM/ /YY) (Responses ranged from 3/05 to 2/06, with one respondent starting

inspections in 5/01)

b. As of January 31, 2006, how many gas IMP inspections have been completed?

Inspections (7 Respondents reported 0 completed inspections, 9 reported

between 1 and 3, 3 reported between 4 and 7, and 1 reported 50,

and 3 indicated no response)

c. As of January 31, 2006, how many gas IMP inspections have been started but not 

completed?

Inspections Æ SKIP TO QUESTION #11 (8 respondents reported 0, 9

respondents reported between 1 and 4, 1 reported 9, 1 reported 12, 4 gave no response).

10. If you have not begun inspections, have you set a date for gas IMP inspections to begin? 

(5) No

(17) Yes Æ On approximately what date will inspections begin?

(Responses ranged from April 2006 through the end of 2006, with 1 respondent saying 2007)

(Note: No response = 1)

 4
Appendix II

Results of State Pipeline Agency Survey

Page 34 GAO-06-946 Natural Gas Pipeline Safety

11. How long do you anticipate it will take your state to inspect all of the gas IMP plans you are

responsible for?

Up to one year .............................................. 23

Between one and two years.......................... 15

Between two and three years........................ 4

More than three years................................... 3

Other time frame (please specify ) ..... 0 (Note: No response = 2)

12. How often do you anticipate that you will inspect each of the gas IMP plans you are responsible 

for?

Once a year................................................... 10

Once every two years................................... 16

Once every three years................................. 14

Other time frame(s) (please

specify )..............................................

6 (Note: No response = 1)

13. Do you plan to report the results of completed gas IMP inspections to OPS? 

No 7 Æ If no, please explain: (Note: 5 explained there is no requirement to report) 

Yes 28

Undecided 10 (Note: No response = 2) 

State Resources

14. How would you describe the number of staff that your agency currently has to implement the 

gas IMP inspection program? 

We do not have enough staff at this time.................. 27

We have enough staff at this time ............................. 18

We have more than enough staff at this time ............ 1 (Note: No response = 1) 

15. How many inspectors do you currently have that can perform gas IMP inspections? 

Inspectors Frequency

0 3

Inspectors 1 14

 2 15

 3 5

 4 7

 5 3

 5
Appendix II

Results of State Pipeline Agency Survey

Page 35 GAO-06-946 Natural Gas Pipeline Safety

16. To date, how many inspectors received OPS training on inspection protocols, and are currently available 

to conduct inspections? Inspectors Frequency

0 4

Inspectors 1 13

 2 17

 3 5

 4 4

 5 4

17. To what extent has the state’s frequency of conducting other pipeline inspections been impacted by

the addition of gas IMP inspections?

Very great extent ..............................2

Great extent ......................................7

Moderate extent ................................17

Some extent ......................................9

Little or no extent ............................7

Don’t know.......................................5

18. To what extent does your agency experience the following challenges as a result of implementing the gas 

IMP inspection program?

A very

great

extent

T

Great

extent

T

Moderate

extent

T

Some

extent

T

Little or 

no extent 

T

Not

sure

T

(No

answer)

a. Staffing challenges?.................... 7 11 15 6 6 2

b. Funding challenges? ................... 5 7 7 10 13 4 1

c. Training challenges?................... 8 16 12 7 3 0 1

d. Another challenge? (please 

 describe ) ...........................

7 5 2 0 0 4 29

e. Another challenge? (please 

 describe ) ............................

2 1 0 1 0 4 39

 6
Appendix II

Results of State Pipeline Agency Survey

Page 36 GAO-06-946 Natural Gas Pipeline Safety

19. How useful has the overall guidance that OPS has provided on your IMP inspection roles and 

responsibilities been?

Extremely useful........................4

Very useful.................................23

Moderately useful .....................9

Somewhat useful........................5

Not at all useful .........................1

Don’t know ................................5

20.

 A. Have the following sources provided you

 information or guidance on conducting gas IMP 

 inspections?

B. Is this a main source of

information or guidance on 

conducting gas IMP inspections?

Yes

T

No

T

No

response

Yes

T

No

T

No

 response 

a. OPS State Liaison?............... 24 19 3 7 34 6

b. Other OPS Regional Staff?... 34 11 2 20 22 4

c. OPS Training Staff? ............. 40 6 1 34 9 4

d. National Association of 

Pipeline Safety 

Representatives (NAPSR)?

22 21 4 5 33 9

e. Other source? (please

describe )....................

14 1 32 7 5 35

21. Please provide any additional comments that you have in this space. If your comments are in response to 

a particular question, please indicate the question number to which you are referring.

Thank you for completing the survey! 

 7
Page 37 GAO-06-946 Natural Gas Pipeline Safety

Appendix III

Contact and Staff Acknowledgments ApendxiI

GAO Contact Katherine A. Siggerud (202) 512-2834 or siggerudk@gao.gov

Staff 

Acknowledgments 

In addition to the individual named above, Jennifer Clayborne, Tamera 

Dorland, Maria Edelstein, Heather Frevert, Cindy Gilbert, Brandon Haller, 

John Mingus, and Sara Vermillion made key contributions to this report.

(542070)
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