United States Government Accountability Office

GAO Testimony 

Before the Subcommittee on Energy and 

Air Quality, Committee on Energy and 

Commerce, House of Representatives

GAS PIPELINE SAFETY

Preliminary Observations 

on the Implementation of 

the Integrity Management 

Program 

Statement of Katherine Siggerud, Director 

Physical Infrastructure Issues 

GAO reposted the Web version of this testimony on April 28, 2006, to reflect 

changes on the highlights page and page 18. The original version was not

updated to provide the latest data to the highlights page. In addition, a 

correction was made on page 18 under Figure 2, the word "five" was replaced

with "three." The sentence should say, "Three operators did not report their 

reassessment plans." 

For Release on Delivery

Expected at 10:00 a.m. EST 

Thursday, April 27, 2006

 

GAO-06-588T 
What GAO Found

United States Government Accountability Office

Why GAO Did This Study

Highlights

Accountability Integrity Reliability

April 27, 2006

GAS PIPELINE SAFETY

Preliminary Observations on the 

Implementation of the Integrity 

Management Program 

Highlights of GAO-06-588T, a testimony 

before the Subcommittee on Energy and 

Air Quality, Committee on Energy and 

Commerce, House of Representatives 

About a dozen people are killed or 

injured in natural gas transmission 

pipeline incidents each year. In an

effort to improve upon this safety

record, the Pipeline Safety 

Improvement Act of 2002 requires 

that operators assess pipeline 

segments in about 20,000 miles of 

highly populated or frequented 

areas for safety risks, such as 

corrosion or welding defects. Half 

of these baseline assessments must 

be done by December 2007, and the 

remainder by December 2012. 

Operators must then repair or 

replace any defective pipelines, and 

reassess these pipeline segments 

for corrosion damage at least every 

7 years. The Pipeline and 

Hazardous Materials Safety 

Administration (PHMSA)

administers this program, called 

gas integrity management, and

inspects operators of interstate

pipelines, while state pipeline 

safety agencies generally inspect 

operators of intrastate pipelines. 

This testimony is based on ongoing 

work for this Subcommittee and

for other committees, as required 

by the 2002 act. It provides 

preliminary results on the safety

effects of (1) PHMSA’s gas integrity 

management program and (2) the 

requirement that operators 

reassess their pipelines at least 

every 7 years. GAO expects to

issue two reports this fall that will 

address these and other topics. 

This testimony also discusses how 

PHMSA has strengthened its 

enforcement program in response 

to recommendations GAO made in

2004. 

Early indications suggest that the gas transmission pipeline integrity 

management program enhances public safety by supplementing existing 

safety standards with risk-based management principles. Operators 

reported that they have assessed about 6,700 miles as of December 2005 and 

completed 338 repairs for problems they are required to address

immediately. Operators told GAO that the primary benefit of the program is 

the comprehensive knowledge they acquire about the condition of their 

pipelines, but they raised concerns about (1) their uncertainty over the level 

of documentation that PHMSA requires and (2) whether their pipelines need 

to be reassessed at least every 7 years. State pipeline officials also agree that 

integrity management enhances safety, but are concerned about their ability 

to obtain sufficient staff and training to inspect operators’ programs. 

The 7-year reassessment requirement represents a midpoint between the 5- 

and 10-year industry consensus standard reassessment requirements for 

higher stress pipelines (pipelines with higher operating pressure in relation 

to wall strength). (However, the industry 5-year interval is less relevant to 

the integrity management program because it applies when not all repairs 

are made. PHMSA’s regulations require that repairs be made as needed.) 

The majority of transmission pipelines in the U.S. are estimated to be higher 

stress pipelines. However, most operators of lower stress pipelines told 

GAO that the 7-year requirement is conservative for their pipelines because

they have found few problems requiring reassessments earlier than the 15 to 

20 years under the industry standard for lower stress pipelines. Operators 

GAO contacted said that periodic reassessments are beneficial for finding 

and preventing problems; but they favored reassessments on severity of risk 

rather than a one-size-fits-all standard. Operators told GAO that requiring 

that pipelines be reassessed more frequently than required under industry 

standards increases costs—which are ultimately passed to consumers—but 

does not increase safety. Operators did not expect that the existence of an 

“overlap period” from 2010 through 2012, when operators will be finishing 

their baseline assessments and beginning some reassessments at the same

time, will create problems in finding resources to conduct reassessments. 

PHMSA has developed a reasonable enforcement strategy framework that is

responsive to GAO’s earlier recommendations. PHMSA’s strategy is aimed at 

reducing pipeline incidents and damage through direct enforcement and 

through prevention involving the pipeline industry and stakeholders (such as 

state regulators). Among other things, the strategy entails (1) using riskbased enforcement and dealing severely with significant noncompliance and 

repeat offenses, (2) increasing knowledge and accountability for results by 

clearly communicating expectations for operators’ compliance, (3) 

developing comprehensive guidance tools and training inspectors on their 

use, and (4) effectively using state inspection capabilities. 

www.gao.gov/cgi-bin/getrpt?GAO-06-588T.

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. 
Mr. Chairman and Members of the Subcommittee: 

We appreciate the opportunity to participate in this oversight hearing on 

the Pipeline Safety Improvement Act of 2002. The act strengthens federal 

pipeline safety programs and enforcement, state oversight of pipeline 

operators, and public education on pipeline safety. The information that 

we and others will provide today should help the Congress as it prepares 

to reauthorize pipeline safety programs. 

My statement is based on the preliminary results of our ongoing work for 

this Subcommittee and others. As directed by the 2002 act, we are 

assessing the effects on safety stemming from (1) the Pipeline and 

Hazardous Materials Safety Administration’s (PHMSA) integrity 

management program for gas transmission pipelines and (2) the 

requirement that pipeline operators reassess their natural gas pipelines for 

certain safety risks at least every 7 years.1

 In addition, I would also like to 

briefly touch on how PHMSA has acted to strengthen its enforcement 

program. I testified on PHMSA’s enforcement program before this 

Subcommittee almost 2 years ago,2

 and believe that this is a good 

opportunity to update you on some positive accomplishments. 

Our work is based on our review of laws, regulations, and other PHMSA 

guidance, as well as discussions with a broad range of stakeholders, 

including industry trade associations, pipeline safety advocate groups, 

state pipeline agencies, pipeline inspection contractors, and consensus 

 1

Under integrity management, operators systematically assess the portions of their 

pipelines that are in highly populated or frequented areas (such as parks) for safety risks. 

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. 

Our work therefore focuses on natural gas. Transmission pipelines transport gas products

from sources to communities and are primarily interstate. Distribution pipelines (local 

distribution companies) that carry natural gas to ultimate users, such as homes, are not

subject to the 2002 act. 

2

GAO, Pipeline Safety: Preliminary Information on the Office of Pipeline Safety’s

Actions to Strengthen Its Enforcement Program, GAO-04-985T (Washington, D.C.: July 20, 

2004) and GAO, Pipeline Safety: Management of the Office of Pipeline Safety’s

Enforcement Program Needs Further Strengthening, GAO-04-801 (Washington, D.C.: July

23, 2004). 

Page 1 GAO-06-588T 
standards organizations.3

 In addition, we surveyed the 47 state pipeline 

agencies responsible for inspecting intrastate gas transmission pipeline 

operators on their plans for conducting inspections of operators’ integrity 

management programs.4 We also contacted 41 pipeline operators about the 

matters that I will discuss today. We chose operators for which integrity 

management could have the greatest impact, all else being equal: larger 

and smaller operators with the highest proportion of pipelines in highly 

populated or frequented areas to total miles of pipeline. These operators 

represent about 60 percent of the miles of pipeline assessed to date. We 

relied on pipeline operators’ professional judgment in reporting on the 

conditions that they found during their assessments of safety risks. The 

information that we obtained from the 41 operators is not necessarily 

generalizable to all operators. As part of our work, we assessed the 

internal controls and the reliability of the data elements needed for this 

engagement, and we determined that the data elements were sufficiently 

reliable for our purposes. We performed our work in accordance with 

generally accepted government auditing standards from August 2005 to

April 2006. 

In summary: 

• Implementation of integrity management is in its early stages as PHMSA’s 

regulations were finalized in 2004. Early indications suggest that the gas 

integrity management program has enhanced public safety by requiring 

that operators identify and address the risks to pipeline segments located 

in areas that are most likely to affect public safety. Operators believe that

the primary benefit of the program is the comprehensive knowledge they

must acquire about the condition of their pipelines. However, operators 

have raised concerns about (1) their uncertainty over the level of 

documentation required by the program and (2) whether the requirement 

to reassess their pipelines at least every 7 years contributes to increased 

safety. PHMSA’s initial inspections of 13 interstate operators’ integrity 

 3

Standards are technical specifications that pertain to products and processes, such as the 

size, strength, or technical performance of a product. National consensus standards are 

developed by standard-setting entities on the basis of an industry consensus. PHMSA’s 

regulations incorporate standards, including reassessment standards, developed by the 

American Society of Mechanical Engineers: Managing the System Integrity of Gas 

Pipelines (ASME B31.8S-2004) and the National Association of Corrosion Engineers:

Standard Recommended Practice -Pipeline External Corrosion Direct Assessment (NACE 

RP0502-2002). 

4

For the purpose of this statement, we treat the District of Columbia as a state pipeline 

agency. 

Page 2 GAO-06-588T 
management programs have shown that operators are doing well in 

assessing their pipelines and making repairs but that they need to better 

document their management practices and decisions. Most state pipeline 

officials reported that they have started or will start integrity management 

inspections of intrastate operators this year. While state officials reported 

that they generally agree that integrity management enhances public 

safety, most are facing challenges in the areas of staffing and training. 

• Overall, pipeline operators have reported to PHMSA that, in the 6,700 

miles of pipeline in highly populated or frequented areas they have 

assessed, they have found 338 problems that required immediate repair or

replacement5

—about 1 problem every 20 miles, on average. The 41 

operators that we contacted—which represent about 60 percent of the 

6,700 miles assessed so far—told us that, if the 7-year requirement were 

not in place, they would reassess the pipeline segments located in highly

populated or frequented areas every 10, 15, or 20 years following industry 

consensus standards.6

 The 7-year reassessment requirement reflects a 

midpoint in relation to industry standards for pipelines operating under 

higher stress (pipelines with higher operating pressure in relation to wall

strength) where as the industry standard for reassessments is 10 years or 

less. (The industry standard requires that pipelines be reassessed at least 

every 5 years if all repairs are not made. PHMSA’s regulations require that

repairs be made as necessary.) However, operators told us that the 7-year

reassessment requirement is conservative for pipelines operating under 

lower stress, where as the industry reassessment standard can extend to 

15 to 20 years. The large majority of transmission pipelines in the U.S. are 

estimated to be higher-stress pipelines, based on information from 

industry associations. Most operators of lower-stress pipelines (21 of the 

26 we contacted) told us that they found few problems during baseline 

assessments that would require reassessments before 15 or 20 years. 

Operators that we contacted believed that periodic reassessments of their 

 5

Operators have reported that about 20,000 miles of pipeline are located in highly populated

or frequented areas. Operators are required to make immediate repairs to their pipelines if 

they (1) determine the remaining strength of the pipe shows a predicted failure pressure of

less than or equal to 1.1 times the maximum allowable operating pressure; (2) identify a 

dent that has any indication of metal loss, cracking, or a stress riser; or (3) determine, in 

their judgment, the assessment results require immediate action. Stress risers are 

corrosion, gouges, or cracks within or between dents.

6

The standards have been accepted by the American National Standards Institute, a private, 

non-profit organization whose mission is to promote and facilitate voluntary consensus 

standards and promote their integrity. The Institute does not approve the technical merits 

of proposed national standards. Rather it ensures that proposed national standards are 

developed in an environment of openness, balance, consensus, and due process. 

Page 3 GAO-06-588T 
pipelines would be beneficial in finding and preventing problems. 

However, they favored conducting reassessments based on severity of risk 

rather than applying a one-size-fits-all standard. Operators told us that 

requiring that pipelines be reassessed more frequently than required under 

industry standards increases costs—which are ultimately passed to 

consumers—but does not increase safety. Operators did not expect that 

the existence of an “overlap period” from 2010 through 2012, when 

operators will be completing baseline assessments and beginning some 

reassessments at the same time, would create problems in finding 

resources to conduct reassessments.7

 The existence of an overlap had 

been an industry concern while the 2002 act was being debated. 

• PHMSA has developed a reasonable enforcement strategy framework that

is responsive to concerns we raised in 2004 that PHMSA had not 

incorporated into its enforcement strategy key features of effective

program management—clear program goals, a well- defined strategy for 

achieving those goals, and performance measures linked to the program 

goals. PHMSA’s recently developed strategy is aimed at reducing pipeline 

incidents and damage through both direct enforcement and prevention. 

The strategy entails, among other things, (1) using risk-based enforcement 

that clearly reflects potential risk and seriousness and dealing severely 

with operators’ significant noncompliance and repeat offenses; (2) 

increasing knowledge of and accountability for results by clearly 

communicating expectations for operators’ compliance; (3) developing

comprehensive guidance tools, along with training inspectors on their use;

and (4) effectively using state inspection capabilities. 

On average, about 3 people have died and about 8 people have been 

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

incidents. The number of incidents has increased from 77 in 1996 to 122 in

2004 and 200 in 2005, primarily due to the greater frequency of property 

damage.8

 Much of this increase may be attributed to the rise in the price of 

gas (which has the effect of lowering the reporting threshold) over the 

past several years and to damage as a result of hurricanes in 2005. 

Background 

 7

Under the 2002 act, operators have until 2012 to complete their baseline assessments. 

However, under the 7-year reassessment requirement, operators that started their baseline 

assessments in 2003 would then need to reassess those pipeline segments in 2010. 

8

An incident, for PHMSA reporting purposes, involves a death; injury requiring 

hospitalization; or property damage, including any loss of natural gas during an incident, of

$50,000 or more. 

Page 4 GAO-06-588T 
As a means of enhancing the security and safety of gas pipelines, the 2002

act included an integrity management structure that, in part, requires 

operators of gas transmission pipelines to systematically assess for safety 

risks the portions of their pipelines located in highly populated or 

frequently used areas, such as parks. Safety risks include corrosion, 

welding defects and failures, third-party damage (e.g., from excavation 

equipment), land movement, and incorrect operation. The act requires that

operators perform these assessments (called baseline assessments) on 

half of the pipeline mileage in highly populated or frequented areas by 

December 2007 and the remainder by December 2012. Those pipeline 

segments potentially facing the greatest risks are to be assessed first. 

Operators must then repair or replace any defective pipelines. Performing 

this form of risk-based assessment is seen by many as having a greater 

potential to improve safety than focusing on compliance with safety 

standards regardless of the threat to pipeline safety. 

The act further provides that pipeline segments in highly populated or 

frequented areas must be reassessed for safety risks at least every 7 years.

PHMSA’s regulations implemented the act by requiring that operators 

reassess their pipelines for corrosion damage every 7 years using an 

assessment technique called confirmatory direct assessment.9

 Under these 

regulations, and mostly consistent with industry national consensus 

standards,10 operators must also reassess their pipeline segments for safety 

risks at least every 10, 15, or 20 years, depending on the pressure under 

which the pipeline segments are operated and the condition of the 

pipeline. 

There are about 900 operators of about 300,000 miles of gas transmission 

and gathering pipelines in the United States. As of December 2005, 

according to PHMSA, 429 of these operators reported that about 20,000 

miles of their pipelines are located in highly populated or frequented areas

(about 7 percent of all transmission pipeline miles). Operators reported 

that they had as many as about 1,600 miles and as few as 0.02 miles of 

pipeline in these areas. 

 9

Confirmatory direct assessment allows for less extensive use of testing methods and is

meant to provide assurance that drastic damage is not taking place. Confirmatory direct 

assessment allows an operator to obtain interim results until it performs a full 

reassessment. 

10As discussed earlier, PHMSA’s regulations do not provide for the 5-year reassessment 

interval that are contained in the industry national consensus standards. 

Page 5 GAO-06-588T 
PHMSA, within the Department of Transportation, administers the 

national regulatory program to ensure the safe transportation of gas and 

hazardous liquids (e.g., oil, gasoline, and anhydrous ammonia) by pipeline. 

The agency attempts to ensure the safe operation of pipelines through 

regulation, national consensus standards, research, education (e.g., to 

prevent excavation-related damage), oversight of the industry through 

inspections, and enforcement when safety problems are found. In general, 

PHMSA retains full responsibility for inspecting and enforcing regulations 

on interstate pipelines but certifies states to perform these functions for 

intrastate pipelines. PHMSA 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. Nine PHMSA inspectors are currently 

devoted to the gas integrity management program. State pipeline agencies 

have about 325 inspectors, about 100 of which are currently able to 

perform integrity management inspections of intrastate gas transmission 

pipeline operators in 47 states. 

While the gas integrity management program is still being implemented, 

early indications suggest that it enhances public safety by supplementing 

existing safety standards with risk-based management principles. Prior to 

the integrity management program, there were, and still are, minimum 

safety standards that operators must meet for the design, construction, 

testing, inspection, operation, and maintenance of gas transmission 

pipelines. These standards apply equally to all pipelines and provide the 

public with a basic level of protection from pipeline failures. However, 

minimum standards do not require operators to identify and address risks 

that are specific to their pipelines, nor do they require operators to assess 

the integrity of their pipelines. While some operators have assessed the 

integrity of some of their pipelines, others have not. Consequently, some 

pipelines have operated for 40 or more years with no assessment. The gas 

integrity management requirements, finalized in 2004, go beyond the 

existing safety standards by requiring operators, regardless of size, to 

routinely assess pipelines in highly populated or frequented areas for 

specific threats, to take action to mitigate the threats, and to document 

management practices and decision-making processes. 

Representatives from the pipeline industry, safety advocate groups, state 

pipeline agencies, and operators we have contacted agree that the integrity 

management program enhances public safety. Some operators noted that,

although the program’s requirements can be costly and time consuming to 

implement, the benefits to date are worth the costs. The primary benefit 

Early Indications 

Suggest that Gas 

Integrity Management 

Enhances Public 

Safety, but Operators 

and States Raise 

Some Concerns About 

Implementation 

Page 6 GAO-06-588T 
identified was the comprehensive knowledge the program requires all 

operators to have of their pipeline systems. For example, under integrity 

management, operators must gather and analyze information about their 

pipelines in highly populated or frequented areas to get a complete picture 

of the condition of those lines. This includes developing maps of the 

pipeline system and gathering information on corrosion protection, 

exposed pipeline, threats from excavation or other third-party damage,

and the installation of automatic shut-off valves. Another benefit cited was 

improved communications within the company. Investigations of pipeline 

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

information that could have prevented an incident but had not shared it 

with employees who needed it most. Integrity management requires 

operators to pull together pipeline data from various sources within the 

company to identify threats to the pipelines, leading to more interaction 

among different departments within pipeline companies. Finally, integrity 

management focuses operator resources on those areas where an incident

could have the greatest impact. 

While industry and operator representatives have provided examples of 

the early benefits of integrity management, operators must report 

semiannually on performance measures that should quantitatively 

demonstrate the impact of the program over time. These measures include 

the total mileage of pipelines and the mileage of pipelines assessed in 

highly populated or frequented areas, as well as the number of repairs 

made and leaks, failures, and incidents identified in these areas. In the 2 

years that operators have reported the results of integrity management, 

they have assessed about 6,700 miles of their 20,000 miles of pipelines 

located in highly populated or frequented areas, and they have completed 

338 repairs that were immediately required and another 998 repairs that 

were less urgent. While it is not possible to determine how many of these 

needed repairs 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 the line down for immediate repair. 

One of the most frequently cited concerns by the 41 operators we 

contacted was the uncertainty about the level of documentation needed to

support their gas integrity management programs. PHMSA requires 

operators to develop an integrity management program and provides a 

Page 7 GAO-06-588T 
broad framework for the elements that should be included in the program. 

Each operator must develop and document specific policies and 

procedures to demonstrate its commitment to compliance with and 

implementation of the integrity management requirements. In addition, an

operator must document any decisions made related to integrity 

management. For example, an operator must document how it identified 

the threats to its pipeline in highly populated or frequented areas and who 

was involved in identifying the threats, their qualifications, and the data

they used. While the operators we contacted 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. Moreover, they 

are concerned that they will not know if they have enough documentation 

until their program has been inspected. After conducting 13 inspections, 

PHMSA found that, while interstate operators are doing well in conducting

assessments and making the identified repairs, they are having difficulty 

overall in the development and documentation of their management 

processes. Another concern raised by most of the operators is the 

requirement to reassess their pipelines at least every 7 years. I will discuss 

the 7-year reassessment requirement in more detail shortly. 

In response to our survey, most state officials indicated that the two most 

challenging areas for them as they begin implementing gas integrity 

management inspections are staffing and training. While most state 

agencies currently have at least two inspectors that can perform 

inspections of operators’ integrity management programs, some state 

pipeline officials responded that they do not have enough inspectors for 

the increased workload and/or their inspectors have not completed the

training required by PHMSA. To ensure that inspectors have the technical 

expertise to conduct integrity management inspections, including 

evaluating operators’ processes and decisions, PHMSA requires inspectors 

to complete 4 classroom and 6 computer-based courses, totaling about 19 

days of training. Three of the classroom courses are part of PHMSA’s core 

training for all inspectors and are generally offered annually. The fourth 

course—a new course that PHMSA established for integrity 

management—was made available to two inspectors from each state in 

2005 and is now offered when there is sufficient demand. The computerbased courses were made available to the states starting in February 2005. 

While the state officials we spoke with agree that the training is necessary,

they are concerned about the amount of time it takes to complete the 

required training and the limited availability of the classroom training. We 

will continue to follow up with state agencies about how these challenges 

will affect their oversight activities. 

Page 8 GAO-06-588T 
I am pleased to report that in response to our 2002 recommendation,11

PHMSA has been working to improve its communication with states about 

their role in overseeing integrity management programs. For example, 

PHMSA’s efforts include (1) inviting state inspectors to attend federal 

inspections, (2) creating a Web site containing inspection information, and 

(3) providing a series of updates through the National Association of 

Pipeline Safety Representatives. Results from the survey of state pipeline

agencies (with most of the states responding thus far) show that the 

majority of state agencies believe that communication from PHMSA has 

been very or extremely useful in helping them understand their roles and 

responsibilities in conducting integrity management inspections.12

Nationwide, pipeline operators reported to PHMSA that they have found, 

on average, about one problem requiring immediate repair or replacement 

for every 20 miles of pipeline assessed in highly populated or frequented

areas. Operators we contacted recognize the benefits of reassessments; 

however, almost all would prefer following the industry national 

consensus standards that use safety risk, rather than a prescribed term, for 

determining when to reassess their pipelines. Most operators expect to be 

able to acquire the services and tools needed to conduct these 

reassessments, including during the overlap period when they are starting 

to reassess pipeline segments while completing baseline assessments. 

As discussed earlier, as of December 2005, operators nationwide have 

notified PHMSA of 338 problems that required immediate repair in the 

6,700 miles in highly populated or frequented areas that they have 

assessed—about one immediate repair required for every 20 miles of 

pipeline assessed in highly populated or frequented areas.13 The number of 

immediate repairs may be due, in part, to some operators systematically 

assessing their pipelines for the first time as a result of the 2002 act. 

7-Year Reassessment 

Requirement May be 

Appropriate for Some 

Operators but 

Conservative for 

Others 

Operators Favor a Riskbased, Rather than a OneSize-Fits-All, Reassessment 

Standard 

 11GAO, Pipeline Safety and Security: Improved Workforce Planning and Communication 

Needed, GAO-02-785 (Washington, D.C.: Aug. 26, 2002).

12Of the 46 state agencies that responded, three state agencies indicated that PHMSA 

information was extremely useful, 23 state agencies said the information was very useful, 9 

state agencies said it was moderately useful, 5 said it was somewhat useful, 1 said it was 

not useful, and 5 had no opinion. 

13Most operators found no or few problems and a handful found more than 10 problems

overall requiring immediate repair. We hope to portray these results when we report to this

Subcommittee and others this fall. 

Page 9 GAO-06-588T 
We contacted 41 transmission operators and local distribution companies 

about their assessment activities. These operators represent about 60 

percent of the 6,700 miles assessed nationwide. Of these, 38 have begun 

assessments and 32 (84 percent) told us that they found few safety 

problems that required reducing pressure and performing immediate 

repairs during baseline assessments. These assessments covered (1) about 

4,100 miles of pipeline in highly populated or frequented areas and (2) 

about 30,000 miles outside of these areas.14 (See fig. 1.) Twenty-five of 

these 38 operators reported finding pipelines in good condition and free of

major defects, requiring only minor repairs or recoating. Seven of these 

operators found two or fewer problems per 100 miles that require 

immediate repairs. Finally, six operators found five or more immediate 

repairs per 100 miles assessed.15 Operators nonetheless found these 

assessments valuable in determining the condition of their pipelines and 

finding damage. The large proportion of these operators reporting that 

they found no or few problems requiring immediate repair is encouraging 

if they represent assessments of their segments facing the greatest risk, as

required by the 2002 act.

 14For example, pipeline operators told us that, when they run an in-line inspection tool 

through a pipeline, they do not collect data solely within the boundary of the highly 

populated or frequented area if the insertion and retrieval points for the tool extend beyond 

the highly populated or frequented area. Rather, they gather information on the pipeline’s 

condition for the entire distance between the insertion and retrieval points because, in

doing so, they gather additional insights into the condition of their pipeline. 

15In figure 1, the results for operator Hi12 show a greater number of problems requiring 

immediate repair (per 100 miles assessed) because it has assessed 11 miles and found 2 of

these problems. The other two operators showing the largest number of problems per 100

miles requiring immediate repair, Lo25 and Lo26, have assessed 77 miles and 370 miles,

respectively. 

Page 10 GAO-06-588T 
[Page Intentionally Left Blank] 

Page 11 GAO-06-588T 
Figure 1: Number of Immediate Repairs Needed as Found During Baseline Assessments 

Immediate repairs found per 100 miles assessed

Operators

Source: GAO interviews with operators.

0

5

10

15

20

25

Lo1 Lo2 Lo3 Lo4 Lo5 Lo6 Lo7 Lo8 Lo9 Lo10 Lo11 Hi1 Hi2 Lo12 Lo13 Lo14 Lo15 Lo16 Hi3

0000000000000000000

Page 12 GAO-06-588T 
Lo17 Hi4 Hi5 Hi6 Hi7 Hi8 Hi9 Lo18 Hi10 Hi11 Lo19 Lo20 Lo21 Lo22 Lo23 Lo24 Hi12 Lo25 Lo26

22.7

19.3

17.7

7.4

6.2

5.0

1.6 1.9

0.8 0.8 0.8 1.2 0.7 000000

Note: The Hi and Lo prefixes to the operator designations denote higher stress and lower stress

pipelines, respectively. To prevent distortion, we excluded 3 of the 41 operators we contacted

because they had assessed 0 miles of pipeline to date. This figure includes the immediate repairs for

pipeline located both inside and outside of highly populated or frequented areas. 

The results for operator Hi12 show a greater number of problems requiring immediate repair (per 100

miles assessed) because it has assessed 11 miles and found 2 of these problems. The other two 

operators showing the largest number of problems per 100 miles requiring immediate repair, Lo25 

and Lo26 have assessed 77 miles and 370 miles, respectively. 

Of the 38 operators that have begun assessment activities, 22 have 

calculated reassessment intervals.16 These operators indicated that based

on the conditions that they identified during baseline assessments; they 

could reassess their pipelines at intervals of 10, 15, or 20 years — as 

allowed by industry consensus standards17 — if the 7-year reassessment 

requirement were not in place. In some cases, operators chose to reassess 

their pipelines at intervals shorter than the industry standards based on 

their own discretion. These baseline assessment findings suggest that 

 16The other 16 operators either (1) have not calculated reassessment intervals; (2) do not

intend to, given the prescriptive federal (7 years) or state (5 years in Texas) reassessment 

requirements; or (3) did not supply us information on their reassessment intervals. 

17 As discussed earlier, the development of these standards met the American National 

Standards Institute’s requirements for openness, balance, consensus, and due process.

Page 13 GAO-06-588T 
overall—at least for the operators we contacted—the 7-year requirement 

is conservative. 

The 7-year reassessment interval represents an approximate midpoint 

between the 5- and 10-year industry reassessment requirements for 

pipelines operating under higher-stress. (The industry standard requires 

that pipelines be reassessed at least every 5 years if all repairs are not 

made. PHMSA’s regulations require that repairs be made as necessary.) 

Higher-stress transmission pipelines are typically those that transport 

natural gas across the country from a gathering area to a local distribution 

company. Operators pointed out that reassessing their pipelines in 7 rather

than 10 years creates additional costs without an equivalent gain in safety;

that is, if the 7-year interval requirement were not in place they would not 

reassess their pipelines for another 3 years consistent with industry 

standards. Operators added that the costs of the more frequent 

reassessments will eventually be passed on to customers. PHMSA does not 

collect information in such a way that would allow us to readily estimate 

the percentage of all pipeline miles in highly populated or frequented areas 

that operate under higher pressure. In the aggregate, the 41 operators that 

we contacted told us that more than three-fourths of their pipeline mileage 

in highly populated or frequented areas is operated under higher pressure. 

Finally, industry data suggest that in the neighborhood of 250,000 miles of 

the 300,000 miles (over 80 percent) of all transmission pipelines 

nationwide may operate under higher pressure. 

Some operators told us that the 7-year reassessment requirement is 

conservative for pipelines that operate under lower stress. This is 

especially true for local distribution companies that use their transmission 

lines mainly to transport natural gas under lower pressure for several 

miles from larger cross-country lines in order to feed smaller distribution 

lines. They pointed out, for example, that in a lower-pressure environment, 

pipelines tend to leak rather than rupture. Leaks involve controlled, slow 

emissions that typically pose little damage or risk to public safety. Twentyone of the 26 lower stress operators (most of which are local distribution 

companies) we contacted that have begun assessments reported finding 

few, if any, conditions during baseline assessments that would require 

immediate repair. (See fig. 1 and accompanying note.) As a result, if the 7-

year requirement did not exist, these local distribution companies would 

likely reassess every 15 to 20 years, following industry consensus 

standards. Some of these operators pointed out that third-party damage 

Page 14 GAO-06-588T 
poses the greatest threat to their systems. Operators added that third-party 

damage, such as dents caused by excavation, can happen at any time and 

that prevention and mitigation measures are the best ways to address it.18

Operators viewed a risk-based reassessment requirement, such as in the 

consensus standard, as valuable for public safety. Operators of both 

higher-stress and lower-stress pipelines indicated a preference for a riskbased reassessment requirement based on engineering standards rather 

than a prescriptive one-size-fits-all standard.19 In addition, a risk-based 

reassessment standard would be consistent with the overall thrust of the 

integrity management program. Some operators noted that reassessing 

pipeline segments with few defects every 7 years takes resources away 

from riskier segments that require more attention. While PHMSA’s 

regulations require that pipeline segments be reassessed only for 

corrosion problems at least every 7 years using the less intensive 

assessment technique of confirmatory direct assessment, some operators 

point out that it has not worked out that way. They told us that, if they are 

going to the effort of assessing pipeline segments to meet the 7-year 

reassessment requirement, they will typically use more extensive testing—

both for corrosion and other problems—than required, because doing so

will provide more comprehensive information. Thus, in most cases, 

operators plan to reassess their pipelines by using the more extensive inline inspections or direct assessment for problems in addition to corrosion 

sooner than required under PHMSA’s rules.20

 18Prevention and mitigation measures include one-call programs, proper marking of the

pipeline’s location, inspection by air, and public education programs. In one-call programs, 

persons who want to dig in an area contact a clearinghouse. The clearinghouse notifies

pipeline operators and others that someone is going to be digging near the pipeline so that

the operator can mark the pipeline’s location prior to the digging work. 

19On a related note, the Congress expressed a general preference for technical standards 

developed by consensus bodies over agency-unique standards in the National Technology

Transfer and Advancement Act of 1995. 

20Direct assessment is a four-step procedure used to identify corrosion and other pipeline 

defects. First, operators analyze information about the physical characteristics of a 

pipeline, such as coating, soil moisture, and past leaks. Second, operators use one or more

tools to examine the pipeline through the soil in areas identified in the first step. Third, 

operators use the results of the above-ground examination to dig holes in intervals along 

the pipeline to examine suspected pipeline problem areas. Finally, operators integrate and 

analyze information gathered during the three previous steps to determine when additional 

digging is necessary and how often pipeline segments should be reassessed. 

Page 15 GAO-06-588T 
Finally, operators are required by PHMSA to take actions in addition to 

periodically reassessing their pipelines. Operators must, on an ongoing 

basis, evaluate their pipelines by integrating operational data with other 

information, including assessment data and risk assessment information, 

to assure the integrity of their pipelines. Operators will use the results 

from the evaluation to identify and remediate specific pipeline threats and 

associated risks. 

Services and Tools Are 

Likely to be Available for 

Reassessments 

Thirty-four of the 41 operators and 4 inspection contractors and 1 

association we contacted (85 percent) told us that the services and tools 

needed to conduct periodic reassessments will likely be available to most 

operators.21 All but one of the operators reported that they plan to rely on 

contractors to conduct all or a portion of their reassessments, and eight of

the 41 operators have signed, or would like to sign, long-term contracts 

that extend contractor services through a number of years. However, few 

have scheduled reassessments with contractors, as reassessments will 

take place several years in the future, and operators are concentrating on 

baseline assessments. 

Thirty of the 38 operators (79 percent) that reported both baseline and

reassessment schedules to us said that they primarily plan to use in-line 

inspection or direct assessment to reassess segments of their pipelines 

located in highly populated or frequented areas. In-line inspection 

contractors that we contacted report that there is capacity within the 

industry to meet current and future operator demands. Unlike the in-line 

inspection method, which is an established practice that 25 of 41 operators 

have used on their pipelines at least once prior to the integrity 

management program, the direct assessment method is new to both 

contractors and operators. Direct assessment contractors told us that 

there is limited expertise in this field, and one contractor said that newer

contractors coming into the market to meet demand may not be qualified.

The operators planning to use direct assessment for their pipelines are 

 21To prepare for this hearing, we contacted the Inline Inspection Association, two 

companies offering in-line inspection services, and two companies offering direct 

assessment services. 

Page 16 GAO-06-588T 
generally local distribution companies with smaller diameter pipelines that 

cannot accommodate in-line inspection tools.22

An industry concern about the 7-year reassessment requirement is that 

operators will be required to conduct reassessments starting in 2010 while 

they are still in the 10-year period (2003-2012) for conducting baseline 

assessments. Industry is concerned that this could create a spike in 

demand for contractor services resulting from an overlap of assessments 

and reassessments from 2010 through 2012, and operators would have to

compete for the limited number of contractors to carry out both. The 

industry was worried that operators might not be able to meet the 

reassessment requirement and that it was unnecessarily burdensome.23

However, the information provided by the operators that we contacted

does not suggest a spike and because baseline assessment activity should 

decrease as they begin to conduct reassessments. (See fig. 2.) Operators 

predict that they will have conducted a large number of baseline 

assessments between 2005 and 2007 in order to meet the statutory 

deadline for completing at least half of their baseline assessments by 

December 2007 –two years before the predicted overlap. 

 22According to industry estimates, 35 percent of all local distribution company pipelines (as

measured in miles likely to be located in highly populated areas) cannot accommodate an 

in-line inspection tool, compared to only about 4 percent of transmission operators’ 

pipelines. 

23The 2002 act allows operators to request a waiver from conducting reassessments when 

inspection tools are not available and when operators need to maintain product supply. 

PHMSA has not issued guidance on conditions under which it would grant a waiver. 

Page 17 GAO-06-588T 
Figure 2: Operators’ Planned Baseline Assessment and Reassessment Schedules 

Miles assessed

Year

Baseline assessments

Reassessments

Source: GAO.

0

500

1000

1500

2000

2500

Pre 2003 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Note: This figure shows the baseline assessments conducted, or planned to be conducted, as well as

the reassessments that are planned in highly populated or frequented areas for the 38 of 41 

operators we contacted. Three operators did not report their reassessment plans. 

There has also been a concern about whether baseline assessments and 

reassessments would affect the natural-gas supply if pipelines are taken

out of service or operate at reduced pressure when repairs are being 

made. We are addressing this issue and will report on it in the fall. 

Page 18 GAO-06-588T 
In 2004, we concluded that we could not assess the effectiveness of 

PHMSA’s enforcement strategy because it had not incorporated key 

features of effective program management—clear program goals, a welldefined strategy for achieving those goals, and performance measures that 

link to the program goals.24 In response to our concerns, PHMSA adopted a 

strategy in August 2005 that focuses on using risk-based enforcement, 

increasing knowledge of and accountability for results, and improving its 

own enforcement activities. The strategy also links these efforts to goals to

reduce and prevent pipeline incidents and damage, in addition to providing 

for periodic assessment of results. While we have neither reviewed the 

revised strategy in depth nor examined how it is being implemented, our 

preliminary view is that it is a reasonable framework that is responsive to

the concerns that we raised in 2004.

PHMSA Has 

Developed a 

Reasonable

Framework for Its 

Enforcement Program 

PHMSA has established overall goals for its enforcement program to 

reduce incidents and damage due to operators’ noncompliance. PHMSA 

also recognizes that incident and damage prevention is important, and its 

strategy includes a goal to influence operators’ actions to this end. To 

meet these goals, PHMSA has developed a multi-pronged strategy that is 

directed at the pipeline industry and stakeholders (such as state 

regulators), ensures that its processes make effective use of its resources. 

For example, PHMSA’s strategy calls for using risk-based enforcement to, 

among other things, take enforcement actions that clearly reflect potential

risk and seriousness and deal severely with significant operator 

noncompliance and repeat offenses. Second, the strategy calls for 

increasing knowledge of and accountability for results through such 

actions as (1) soliciting input from operators, associations, and other 

stakeholders in developing and refining regulations, inspection protocols, 

and other guidance; (2) clearly communicating expectations for 

compliance and sharing lessons learned; and (3) assessing operator and 

industry compliance performance and making this information available. 

Third, the strategy, among other things, calls for improving PHMSA’s own 

enforcement activities by developing comprehensive guidance tools, 

training inspectors on their use, and effectively using state inspection 

capabilities. 

Finally, to understand the progress being made in encouraging pipeline 

operators to improve their level of safety and, as a result, reduce accidents 

 24 GAO-04-801. 

Page 19 GAO-06-588T 
and fatalities, PHMSA annually will assess its overall enforcement results 

as well as various components of the program. Some of the program 

elements that it may assess are inspection and enforcement processes, 

such as the completeness and availability of compliance guidance, the 

presentation of operator and industry performance data, and the quality of

inspection documentation and evidence. 

Our work to date suggests that PHMSA’s gas integrity management 

program should enhance pipeline safety, and operators support it. We 

have not identified issues that threaten the overall framework of integrity 

management. We expect to provide additional insights into issues 

involving state pipeline agency staffing and training and the 7-year 

reassessment requirement when we report to this Subcommittee and 

others this fall. 

Because the program is in its early phase of implementation, PHMSA is 

learning how to oversee the program, and operators are learning how to 

meet its requirements. Similarly, operators are in the early stages of 

assessing their pipelines for safety problems. This means that the integrity 

management program will be going through this shakedown period for 

another year or two as PHMSA and operators continue to gain experience.

Mr. Chairman, this concludes my prepared statement. I would be pleased

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

Subcommittee might have. 

For further information on this testimony, please contact Katherine 

Siggerud at (202) 512-2834 or siggerudk@gao.gov. Individuals making key 

contributions to this testimony were Jennifer Clayborne, Anne Dilger, Seth

Dykes, Maria Edelstein, Heather Frevert, Matthew LaTour, Bonnie 

Pignatiello Leer, James Ratzenberger, and Sara Vermillion. 

Concluding 

Observations 

GAO Contacts and 

Staff 

Acknowledgement 

Page 20 GAO-06-588T (542090) 
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