United States Government Accountability Office

GAO Testimony 

Before the Subcommittee on Highways, 

Transit and Pipelines, Committee on 

Transportation and Infrastructure, House 

of Representatives

GAS PIPELINE SAFETY

Preliminary Observations 

on the Integrity 

Management Program and 

7-Year Reassessment 

Requirement 

Statement of Katherine Siggerud, Director 

Physical Infrastructure Issues 

For Release on Delivery

Expected at 10:00 a.m. EST 

Thursday, March 16, 2006

 

GAO-06-474T 
What GAO Found

United States Government Accountability Office

Why GAO Did This Study

Highlights

Accountability Integrity Reliability

March 16, 2006

GAS PIPELINE SAFETY

Preliminary Observations on the Integrity 

Management Program and 7-Year 

Reassessment Requirement 

Highlights of GAO-06-474T, a testimony 

before the Subcommittee on Highways, 

Transit and Pipelines, Committee on 

Transportation and Infrastructure, 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, welding defects, or 

incorrect operation. 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.

This testimony is based on ongoing 

work for this Subcommittee and

for other committees, as required 

by the 2002 act. The testimony

provides preliminary results on the

safety effects of (1) PHMSA’s gas 

integrity management program and

(2) the requirement that operators 

reassess their natural gas pipelines

at least every 7 years. It also

discusses how PHMSA has acted to 

strengthen its enforcement

program in response to 

recommendations GAO made in

2004. 

GAO expects to issue two reports 

this fall that will address these and 

other topics. 

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 have

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 must acquire about the condition of their 

pipelines. For some operators, the integrity management program has 

prompted such assessments for the first time. Operators 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.

The 7-year reassessment requirement is generally consistent with the 

industry consensus standard of at least every 5 to 10 years for reassessing 

pipelines operating under higher stress (higher operating pressure in relation 

to wall strength). The majority of transmission pipelines in the U.S. are 

estimated to be higher stress pipelines. However, most operators told GAO 

that the 7-year requirement is conservative for pipelines that operate under 

lower stress because they found few problems requiring reassessments 

earlier than the 15 to 20 years under the industry standard. 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 did not expect that the 

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

will be conducting baseline assessments and reassessments at the same 

time, would 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. 

Pipeline Failure Resulting from Corrosion 

Source: CC Technologies.

www.gao.gov/cgi-bin/getrpt?GAO-06-474T.

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, 

 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 unless they are operated by companies that also operate 

transmission pipelines. 

2

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

to Strengthen Its Enforcement Program, GAO-04-875T (Washington, D.C.: June 16, 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-06-474T 
state pipeline regulators, and consensus standards organizations.3

 In 

addition, we contacted 25 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 half of the 

miles of pipeline assessed to date.4

 We relied on pipeline operators’ 

professional judgment in reporting on the conditions that they found 

during their assessments of safety risks. 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 March 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 11 operators’ integrity 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. 

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

6,700 miles of pipeline they have assessed, they have found 338 problems 

 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 reassessment standards developed by the American Society of 

Mechanical Engineers: Managing the System Integrity of Gas Pipelines (ASME B31.8S2004). 

4

The information that we obtained from the 25 operators is not necessarily generalizable to 

all operators. 

Page 2 GAO-06-474T 
that required immediate repair or replacement5

—about 1 problem every 20 

miles, on average. The 25 operators that we contacted—which represent 

about half 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. The 7-year reassessment 

requirement is similar to industry standards for pipelines operating under

higher-stress (higher operating pressure in relation to wall strength) where 

the industry standard for reassessments is no more than 5 to 10 years, 

depending on operating pressure. However, operators told us that the 7-

year reassessment requirement is conservative for pipelines operating 

under lower-stress, where 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 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 pipelines will be beneficial in finding 

and preventing problems. However, they favored conducting 

reassessments based on severity of risk rather than applying a one-sizefits-all standard. Operators did not expect that the existence of an “overlap 

period” from 2010 through 2012, when operators will be completing 

baseline assessments and beginning reassessments at the same time, 

would create problems in finding resources to conduct reassessments.6

The existence of an overlap was an industry concern while the 2002 act 

was being debated. 

• PHMSA has developed a reasonable enforcement strategy framework that

is responsive to the recommendations that we made in 2004. PHMSA’s 

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 

 5

Operators have reported that about 20,000 miles of pipelines 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. 

6

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. 

Page 3 GAO-06-474T 
noncompliance and repeat offenses; (2) increasing knowledge and 

accountability for results by clearly communicating expectations for 

operator 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 each year over the last 10 years in natural gas transmission 

pipeline incidents. The number of incidents has increased from 77 in 1996

to 122 and 200 in 2004 and 2005, respectively, mostly reflecting more 

frequent occurrence of property damage.7

 Much of this increase may be 

attributed to increases 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. 

As a means of enhancing the security and safety of gas pipelines, the 2002

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

operators of gas transmission pipelines 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 defective pipelines. Risk-based 

assessments are 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 

Background 

 7

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

hospitalization; or property damage, including the price of natural gas lost during an

incident, of $50,000 or more. 

Page 4 GAO-06-474T 
assessment technique called confirmatory direct assessment.8

 Under these 

regulations, and consistent with industry national consensus standards, 

operators must also reassess their pipeline segments for any safety risk at

least every 5, 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 lie 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.

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. 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. In addition, PHMSA is assisted by 

inspectors in 48 states, the District of Columbia, and Puerto Rico. 

 8

Confirmatory direct assessment uses principles and techniques of direct assessment to 

identify internal and external corrosion of pipelines. Under confirmatory direct 

assessment, operators can meet PHMSA’s rules by using a single assessment tool, rather 

than several tools or approaches that would provide more comprehensive information. 

Page 5 GAO-06-474T 
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 did assess the 

integrity of some of their pipelines, others did not. Some pipelines have 

been in operation 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, take action to mitigate the threats, and document 

management practices and decision-making processes. 

Representatives from the pipeline industry, safety advocate groups, 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 cost. The primary benefit 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 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 been shared 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 in those areas where an incident could have 

the greatest impact. 

Early Indications 

Suggest that Gas 

Integrity Management 

Enhances Public 

Safety, but Operators 

Raise Some Concerns 

About 

Implementation 

Page 6 GAO-06-474T 
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 25 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 

broad framework for the elements that should be included in the program. 

Each operator must develop and document specific policies and 

procedures to demonstrate their commitment to compliance 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 did not disagree 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 

11 inspections, PHMSA found that, while 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 

Page 7 GAO-06-474T 
is the requirement to reassess their pipelines at least every 7 years. I will 

discuss the 7-year reassessment requirement in more detail shortly. 

As part of our assessment of the integrity management program, we are 

also examining how PHMSA and state pipeline agencies plan to oversee 

operator implementation of the program. To help federal and state 

inspectors prepare for and conduct integrity management inspections, 

PHMSA developed detailed inspection protocols tied to the integrity 

management regulations and a series of training courses covering the 

protocols and other relevant topics, such as corrosion and in-line 

inspection.9

 Furthermore, in response to our 2002 recommendation,10

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 website containing inspection information, and 

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

Pipeline Safety Representatives. I am pleased to report that preliminary 

results from an ongoing survey of state pipeline agencies (with more than 

half the states responding thus far) show that the majority of states that 

reported believe that the communication from PHMSA has been very or 

extremely useful in helping them understand their role and responsibilities 

in conducting integrity management inspections.11

 9

In-line inspections are accomplished by running specialized tools through pipelines to 

detect problems, such as reduced wall thickness and cracks. 

10GAO, Pipeline Safety and Security: Improved Workforce Planning and Communication 

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

11Twenty-nine states responded to the survey as of early March 2006. Three states indicated 

that PHMSA information was extremely useful, 15 states said the information was very 

useful, 3 states said it was moderately useful, 4 said it was somewhat useful, and 4 had no 

opinion. 

Page 8 GAO-06-474T 
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 an 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 they have assessed—about one immediate repair required for 

every 20 miles of pipeline assessed in highly populated or frequented 

areas. 

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. Of the 25 transmission operators and local distribution 

companies that we contacted, most told us that they found few safety 

problems that required reducing pressure and performing immediate 

repairs during baseline assessments covering (1) about 3,000 miles of 

pipeline in highly populated or frequented areas and about (2) 35,000 miles 

outside of these areas.12 (See fig. 1.) Most operators reported finding 

pipelines in good condition and free of major defects, requiring only minor 

repairs or recoating. A few operators found more than 10 immediate 

repairs. Operators nonetheless found these assessments valuable in 

determining the condition of their pipelines and finding damage. 

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 

 12Pipeline operators, for example, told us that, when they run an in-line inspection tool 

through a pipeline, they will 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. 

Page 9 GAO-06-474T 
Figure 1: Number of Immediate Repairs Needed as Found During Baseline Assessments 

Operators

Immediate repairs found per 100 miles assessed

Source: GAO interviews with operators.

0

5

10

15

20

25

A B C D E F G H I J K L M N O P Q R S T U V

Note: To prevent distortion, we excluded 3 of the 25 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. 

Most of the operators told us that, if the 7-year reassessment requirement 

was not in place, they would respond to the conditions that they identified 

during baseline assessments by reassessing their pipelines every 10, 15, or

20 years, based on industry consensus standards. These baseline 

assessment findings suggest that—at least for the operators we 

contacted—the 7-year requirement is conservative. However, the 7-year 

reassessment requirement may be more appropriate for higher-stress 

pipelines than for lower-stress pipelines. 

The 7-year reassessment requirement is generally more consistent with 

scientific- and engineering-based intervals for pipelines operating under 

higher-stress. Higher-stress transmission pipelines are typically those that 

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

distribution company. For higher-stress pipelines, the industry consensus 

standard sets maximum reassessment periods at 5 or 10 years, depending

on operating pressure. 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 

Page 10 GAO-06-474T 
pressure. For the 25 operators that we contacted, the operators told us 

that about three-fourths of their pipeline mileage in highly populated or 

frequented areas operated at higher pressures. 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 at 

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 pressures 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 create little damage or risk to public safety. Most 

local distribution companies we spoke with reported finding few, if any, 

conditions during baseline assessments that would necessitate another 

assessment within 7 years. As a result, if the 7-year requirement did not 

exist, the local distribution companies would likely reassess every 15 to 20

years following industry consensus standards. Some of these operators 

often pointed out that since third-party damage poses the greatest threat

to their systems. Operators added that third-party damage can happen at 

any time and that prevention and mitigation measures are the best ways to 

address it.13

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

consensus standard as valuable for public safety. Operators of both higherstress and lower-stress pipelines indicated a preference for a risk-based 

reassessment requirement based on engineering standards rather than a 

prescriptive one-size-fits-all standard.14 Such 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 

 13Prevention 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 their pipeline, so

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

14On 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. 

Page 11 GAO-06-474T 
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 a less intensive assessment technique (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—for both corrosion and for other 

problems—than required, because doing so will provide more 

comprehensive information. Thus, in most cases, operators plan to 

reassess their pipelines by using in-line inspections or direct assessment 

for problems in addition to corrosion sooner than required under PHMSA’s 

rules.15

Services and Tools Are 

Likely to be Available for 

Reassessments 

Most operators and inspection contractors we contacted told us that the 

services and tools needed to conduct periodic reassessments will likely be 

available to most operators. All of the operators reported that they plan to

rely on contractors to conduct all or a portion of their reassessments and 

some 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 they are several years in the 

future, and operators are concentrating on baseline assessments. 

Nineteen of the 21 operators that reported both baseline and reassessment 

schedules to us said that 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 many 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.16 The operators planning to 

 15Direct assessment is used to identify corrosion and other defects in pipelines. It is used 

when in-line inspection cannot be used and to avoid interrupting gas supply to a

community fed by a single pipeline. Direct assessment involves several steps, including 

digging holes at intervals along a pipeline to examine suspected problem areas. 

16To prepare for this hearing, we contacted the Inline Inspection Association, one company 

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

Page 12 GAO-06-474T 
use direct assessment for their pipelines are generally local distribution 

companies with smaller diameter pipelines that cannot accommodate inline inspection tools.17

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 was 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.18

Most operators that we contacted do not anticipate a spike and baseline 

activity should decrease as they begin to conduct reassessments. (See fig.

2.) They predict that operators 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 (2 years before the predicted overlap). 

 17According 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. 

18The 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 13 GAO-06-474T 
Figure 2: Operators’ Planned Baseline Assessment and Reassessment Schedules 

Miles assessed

Year

Baseline assessments

Reassessments

Source: GAO.

0

200

400

600

800

1,000

1,200

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 20 of 25 

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

There has also been a concern about whether baseline assessments and 

reassessments would affect natural gas supply if pipelines are taken out of 

service or operate at reduced pressures when repairs are being made. We

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

Recently, PHMSA reassessed its approach for enforcing pipeline safety

standards in response to our concern that it lacked a comprehensive 

enforcement strategy. In August 2005, PHMSA adopted a strategy 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 

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

PHMSA Has 

Developed a 

Reasonable

Framework for Its 

Enforcement Program 

Page 14 GAO-06-474T 
reasonable framework that is responsive to the concerns that we raised in 

2004. 

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), and ensuring 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 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 through developing comprehensive guidance tools 

and training inspectors on their use, and effectively using state inspection 

capabilities. 

Finally, to understand progress being made in encouraging pipeline 

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

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 major issues that need to be addressed at this time. We 

expect to provide additional insights into these issues when we report to 

this Subcommittee and others this fall. 

Concluding 

Observations 

Page 15 GAO-06-474T 
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 shake down 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. 

GAO Contacts and 

Staff 

Acknowledgement 

Page 16 GAO-06-474T (542087) 
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