a

GAO

United States Government Accountability Office

Report to Congressional Committees

September 2006 NATURAL GAS 

PIPELINE SAFETY

Risk-Based Standards 

Should Allow 

Operators to Better 

Tailor Reassessments 

to Pipeline Threats

GAO-06-945
What GAO Found

United States Government Accountability Office

Why GAO Did This Study

Highlights

Accountability Integrity Reliability

September 2006

NATURAL GAS PIPELINE SAFETY

Risk-Based Standards Should Allow 

Operators to Better Tailor 

Reassessments to Pipeline Threats 

Highlights of GAO-06-945, a report to 

congressional committees 

The Pipeline Safety Improvement

Act of 2002 requires that operators 

(1) assess gas transmission pipeline 

segments in about 20,000 miles of 

highly populated or frequently used 

areas by 2012 for safety threats,

such as incorrect operation and 

corrosion (called baseline 

assessments), (2) remedy defects, 

and (3) reassess these segments at

least every 7 years. Under the 

Pipeline and Hazardous Materials 

Safety Administration’s (PHMSA) 

regulations, operators must

reassess their pipeline segments for 

corrosion at least every 7 years and

for all safety threats at least every 

10, 15, or 20 years, based on

industry consensus standards—and 

more frequently if conditions 

warrant. Operators must also carry 

out other prevention and mitigation

measures. 

To meet a requirement in the 2002

act, this study addresses how the 

results of baseline assessments and 

other information inform us on the 

need to reassess gas transmission 

pipelines every 7 years and 

whether inspection services and 

tools are likely to be available to do 

so, among other things. In

conducting its work, GAO 

contacted 52 operators that have

carried out about two-thirds of the 

baseline assessments conducted to

date. 

What GAO Recommends

The Congress should consider 

allowing gas transmission pipeline 

operators to reassess their pipelines 

using risk-based standards. In 

commenting on a draft of this report,

the Department of Transportation 

generally agreed with it and the 

Department of Energy stated that it 

had no comments. 

Periodic reassessments of gas transmission pipelines are useful because 

safety threats can change. However, the 7-year requirement appears to be

conservative because (1) most operators found few major problems during 

baseline assessments, and (2) serious pipeline incidents involving corrosion 

are rare, among other reasons. Through December 2005 (latest data 

available), 76 percent of the operators (182 of 241) that had begun baseline 

assessments reported to PHMSA that their pipelines required only minor 

repairs. These results are encouraging because operators are required to 

assess their riskiest segments first. Since operators are also required to 

repair these problems, the overall safety and condition of their pipelines 

should be enhanced before reassessments begin. In addition, PHMSA data 

suggest that serious gas transmission pipeline problems due to corrosion are 

rare. For example, there have been no deaths or injuries as a result of 

incidents due to corrosion since 2001. Of the 52 operators contacted that 

have calculated reassessment intervals, the large majority (20 of 23) told 

GAO that based on conditions identified during baseline assessments, they 

could safely reassess their pipelines for corrosion, every 10, 15, or 20 years—

as industry consensus standards prescribe unless pipeline conditions 

warrant an earlier assessment. 

Sufficient resources may be available for operators’ reassessment activities, 

but some uncertainty exists. For the most part, the 52 operators that GAO 

contacted expect to be able to obtain the services and tools needed through 

2012. However, they expressed some concern about whether enough 

qualified vendors for the confirmatory and direct assessment methods 

(above-ground inspections followed by excavations) would be available. 

Industry associations and GAO attempted to determine the degree to which 

activity would increase from 2010 to 2012, when operators begin reassessing

pipelines while completing baseline assessments. An industry effort showed 

an increase in assessment and reassessment activity, but GAO’s showed a 

decrease. The reasons for the differences are not clear but may be due, in 

part, to differences in the operators contacted and the methodologies used 

in collecting this information. 

Framework for Assessing and Reassessing Pipelines for Safety Threats 

www.gao.gov/cgi-bin/getrpt?GAO-06-945.

To view the full product, including the scope 

and methodology, click on the link above. 

For more information, contact Katherine 

Siggerud (202) 512-2834 or

siggerudk@gao.gov. 
Page i GAO-06-945 Pipeline Reassessment Requirements

Contents

Letter 1

Results in Brief 3

Background 7

The 7-Year Reassessment Requirement Appears to Be

Conservative 11

Sufficient Resources May Be Available for Pipeline

Reassessments 17

Conclusions 23

Matter for Congressional Consideration 25

Agency Comments and Our Evaluation 25

Appendixes

Appendix I: Impact of Periodic Reassessments on Natural Gas Supply 

May Be Less than Foreseen 27

Appendix II: Scope and Methodology 37

Other Aspects of Our Work 39

Organizations Contacted 40

Appendix III: Contact and Staff Acknowledgments 42

Figures Figure 1: Most Operators Reported That Their Gas Transmission 

Pipelines Are in Good Condition, as of December 2005 4

Figure 2: Reassessments Every 7 Years for Corrosion Supplement 

Broader Periodic Reassessments 10

Figure 3: Operators Contacted Plan to Reassess Nearly All of the 

Mileage in Highly Populated or Frequently Used Areas 

Using In-line Inspection and Direct Assessment Tools 19

Figure 4: Baseline Assessment and Reassessment Activities Are 

Expected to Decrease during the Overlap Period, 

According to Operators We Contacted 21

Figure 5: Baseline and Reassessment Activities Are Expected to 

Increase during the Overlap Period, According to INGAA 

and AGA 22

Figure 6: GAO and INGAA/AGA Results Show Different Trends in 

Assessment Activity during the Overlap Period 23

Figure 7: Parallel Natural Gas Transmission Pipelines Can Help 

Maintain Product Supply 30
Contents

Page ii GAO-06-945 Pipeline Reassessment Requirements

Abbreviations

AGA American Gas Association

INGAA Interstate Natural Gas Association of America

PHMSA Pipeline and Hazardous Materials Safety Administration

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

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

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

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

reproduce this material separately.
Page 1 GAO-06-945 Pipeline Reassessment Requirements

United States Government Accountability Office

Washington, D.C. 20548

A

September 8, 2006 Letr

Congressional Committees:

Gas transmission pipelines are one of the nation’s safest modes of freight 

transportation: nationwide about three people have died and about eight 

have been injured annually, on average, over the past decade because of 

natural gas pipeline incidents from all causes.1

 To enhance the safety of gas 

transmission pipelines, the Pipeline Safety Improvement Act of 2002 

requires that operators of these pipelines develop programs to assess and 

mitigate safety threats, such as leaks or ruptures due to incorrect operation 

or corrosion, to pipeline segments that are located in highly populated and 

frequently used areas, such as parks. Specifically, operators are required to 

perform baseline assessments on one-half of the gas transmission pipeline 

mileage located in these areas by December 2007 and the remainder by 

December 2012. Pipeline segments that potentially face the greatest risks 

of failure from leaks or ruptures are to be assessed first. 

The 2002 act also requires that operators reassess these pipeline segments 

for safety threats at least every 7 years. Under flexibility provided by the 

act, the federal regulator—the Pipeline and Hazardous Materials Safety 

Administration (PHMSA)—requires that operators reassess these pipeline 

segments for corrosion damage at least every 7 years in its implementing 

regulations, because corrosion is the most frequent cause of failures that 

can occur over time.2

 It also incorporated, as mandatory, voluntary industry 

consensus standards on maximum reassessment intervals into these 

regulations for other types of safety threats. The industry standards require 

that operators reassess gas pipelines at least every 10, 15, or 20 years for all 

safety risks, depending primarily on the condition of the pipelines and the 

pressure under which they operate. If conditions warrant, reassessments 

must occur more frequently. 

1

Transmission pipelines move products from sources to communities. An incident, for 

PHMSA reporting purposes, involves a death, an injury requiring hospitalization, or property 

damage (including the value of any loss of gas) of $50,000 or more.

2

Other types of failures are independent of time, such as damage from excavation, land 

movement, or incorrect operation. 
Page 2 GAO-06-945 Pipeline Reassessment Requirements

The 2002 act required that we assess the 7-year reassessment requirement. 

To do so, we examined (1) the extent to which findings from baseline 

assessments and other information inform us about the need to reassess 

gas transmission pipelines for safety risks at least every 7 years and (2) the 

ability of operators to obtain the services and tools needed to perform the 

reassessments. These two topics are the main focus of this report. We also 

examined the potential impact of periodic assessments on the nation’s 

natural gas supply. (See app. I.) This report deals mostly with natural gas 

transmission pipelines, which represent the overwhelming majority of gas 

pipelines.3

To understand how the findings from operators’ baseline assessments and 

other information inform us about the need to reassess gas transmission 

pipelines at least every 7 years, we reviewed laws, regulations, and other 

PHMSA guidance. We discussed this issue with PHMSA, other federal 

agencies, industry associations, companies that perform research in this 

area, state safety representatives, and safety advocacy groups. We also 

obtained information from 52 gas pipeline operators for which baseline 

assessments and reassessments could have the greatest impact, all else 

being equal: larger and smaller transmission pipelines and local 

distribution companies (pipeline companies that take gas from 

transmission pipelines and distribute it to end users) with the highest 

proportion of pipeline miles in highly populated and frequently used areas 

to total system miles. Overall, these operators have assessed about 21 

percent of the 20,000 miles of gas transmission pipeline that operators have 

reported as being within highly populated or frequently used areas.4

 In 

addition, we analyzed data from PHMSA for 241 operators that reported, in 

2004 and 2005, on the number of immediate repairs conducted after 

completing their baseline assessments.5

 To determine the extent to which 

gas transmission pipeline operators and local distribution companies will 

likely have the resources to reassess their pipelines at least every 7 years, 

we asked operators, inspection tool contractors, and industry associations 

about the availability of equipment, equipment operators, and data analysts 

3

Other types of gas pipelines transport hydrogen and carbon dioxide. 

4

It would have been insightful to be able to assess the effects of operators’ assessment 

activity in relation to the volume of gas flowing through their pipelines and the overall 

capacity of the pipelines. However, this information was not readily available. 

5

Nationwide, there are about 900 operators, 447 of which have reported to PHMSA that they 

operate pipelines in highly populated or frequently used areas. Of these, 241 have reported 

to PHMSA that they have completed some baseline assessments.
Page 3 GAO-06-945 Pipeline Reassessment Requirements

to interpret results. We also synthesized the information from the 52 

operators to determine the aggregate level of actual and planned 

assessments and reassessments through 2012 and compared our findings 

with the results from an Interstate Natural Gas Association of America and 

American Gas Association data collection effort on the same topic. 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 between August 2005 and August 2006 in accordance with generally 

accepted government auditing standards. (See app. II for additional details 

on our scope and methodology.)

Results in Brief Periodic reassessments of pipeline threats are beneficial because threats—

such as the corrosive nature of the gas being transported—can change over 

time. Baseline assessment findings conducted to date and the generally 

safe condition of gas transmission pipelines, suggest that the 7-year 

reassessment requirement appears to be conservative. Through December 

2005 (latest data available), 76 percent of the operators (182 of 241) 

reporting baseline assessment activity reported to PHMSA that their gas 

transmission pipelines were in good condition and free of major defects, 

requiring only minor repairs. (See fig. 1.) Most of the 340 problems reported 

were concentrated in just seven pipelines.6

 (These assessments reported by 

the 241 operators covered about 6,700 miles, or about one-third of the 

nationwide total to be assessed by 2012.) Because PHMSA does not require 

operators to identify the nature of the problems, we do not know how 

many, if any, were corrosion related. 

6

Pipeline operators are required to report the number of scheduled and immediate repairs 

completed. They may have found other problems but not have completed the repairs. These 

repairs are reported only after they are completed.
Page 4 GAO-06-945 Pipeline Reassessment Requirements

Figure 1: Most Operators Reported That Their Gas Transmission Pipelines Are in 

Good Condition, as of December 2005 

Note: Results of 241 operators that reported to PHMSA that they completed 6,700 miles of baseline 

assessments. Of those operators that reported no problems, 82 operate smaller pipeline systems (1 to 

49 miles), 41 operate mid-sized systems (50 to 199 miles) and 59 operate larger systems (200 or more 

miles).

These results are encouraging, since operators are required to assess their 

riskiest segments first and 54 percent of the operators we contacted that 

have begun baseline assessments told us that they had not conducted riskbased assessments before the onset of the gas integrity management 

program. This suggests that, overall, operators that have thus performed 

baselines assessments are doing a good job in managing corrosion. 

Furthermore, since operators are required to repair these gas transmission 

pipelines the overall safety and condition of the pipeline system should be 

improved before reassessments begin toward the end of the decade. In 

addition, PHMSA data show corrosion incidents are rare: over the past 5-

1/2 years (from January 2001 through early July 2006), there were 26 

corrosion-related incidents over the 295,000-mile transmission system per 

year, on average—none of which resulted in death or injury.7

 

7

In the last 101⁄2 years, PHMSA data show that 236 corrosion-related incidents occurred, only 

2 of which resulted in deaths or injuries. One of the incidents resulted in 12 deaths and two 

injuries. The other incident resulted in one injury. Neither incident occurred in a highly 

populated or frequently used area. 

52 

7 

0 50 100 150 200 

10 or more

1 to 9 

0 182 0% of 

total problems

42% of 

total problems

58% of 

total problems

Number of operators

Number of immediate repairs needed 

Source: GAO presentation of PHMSA data.
Page 5 GAO-06-945 Pipeline Reassessment Requirements

Of the 52 operators that we contacted, 23 have calculated reassessment 

intervals. Based on conditions identified during baseline assessments, 20 of 

these 23 operators indicated that they would reassess their gas 

transmission pipelines at the maximum allowable intervals prescribed by 

industry consensus standards—if the 7-year reassessment requirement 

were not in place.8

 Most operators we contacted (42 of 52 or 81 percent) 

told us that they prefer following industry consensus standards that base 

reassessment intervals on the characteristics and conditions of pipelines 

and that were developed using historical information and research. 

Although the industry consensus standards recognize that corrosion does 

not occur at a rapid rate, they allow for maximum reassessment intervals 

for time-dependent threats of 10, 15, or 20 years only if the operator can 

adequately demonstrate that corrosion will not become a threat within the 

chosen time interval. If not, then the reassessment must occur more 

frequently, perhaps at 7 or even fewer years. Federal policy encourages the 

use of industry consensus standards, and PHMSA’s implementing 

regulations incorporate three other industry consensus standards. 

PHMSA and state pipeline agencies are conducting inspections that should 

serve as a check as to whether operators have identified threats facing 

these gas transmission pipeline segments and have determined appropriate 

reassessment intervals. Initial results from 137 federal and state 

inspections show that operators are doing well on assessing their pipelines 

and making repairs. PHMSA and state agencies plan to inspect all 

operators’ compliance with integrity management, including reassessment 

requirements and complete most of them by 2009 to, among other things, 

ensure that operators continually and appropriately assess the conditions 

of their pipeline segments. Finally, basing reassessments for corrosion on 

risk would be consistent with the risk-based approach to improving 

pipeline safety (called integrity management) set out in the 2002 act. We 

recently reported that PHMSA’s implementation of the gas integrity 

management program is designed to enhance public safety.9

8

The remaining three operators told us that they could reassess their pipelines at intervals 

shorter than the industry consensus standards but longer than 7 years, based on the 

condition of their pipelines.

9

For a discussion on the effect of integrity management on public safety, see Natural Gas 

Pipeline Safety: Integrity Management Enhances Public Safety, but Consistency of 

Performance Measures Should Be Improved, GAO-06-946 (Washington, D.C.: Sept. 8, 2006).
Page 6 GAO-06-945 Pipeline Reassessment Requirements

Sufficient resources may be available for operators to reassess their gas 

transmission pipelines, but some uncertainty exists. For the most part, the 

52 operators and four inspection contractors we contacted told us that 

services and tools needed to conduct assessments have been readily 

available for baseline assessments, and they do not anticipate difficulties 

obtaining these resources in the future. Operators that reported both 

baseline and reassessment schedules told us they plan to reassess 42 

percent of their pipeline miles in highly populated or frequently used areas 

using in-line inspection.10 Operators we contacted said that the in-line 

inspection industry is well established and has the capacity to expand 

readily. Operators plan to use direct assessment or confirmatory direct 

assessment methods in reassessing another 54 percent of their pipeline 

miles.11 However, they told us that expertise in direct assessment methods 

is limited; therefore, they may not be as readily available to all operators. 

Industry associations and we asked operators to estimate the number of 

miles of gas transmission pipeline they planned to assess through 2012 in 

order to determine whether an increase in overall assessment activity 

would occur because of the overlap between completing baseline 

assessments and beginning reassessments from 2010 through 2012. The 

results were conflicting: the industry found an increase in activity, while 

we found a decrease. The reasons for these contrasting findings are unclear 

but may be due, in part, to the difference in methods used in collecting this 

information. 

We suggest that the Congress amend the Pipeline Safety Improvement Act 

of 2002 to permit pipeline operators to reassess their gas transmission 

pipeline segments at intervals based on risk factors, technical data, and 

engineering analyses. Such a revision would allow PHMSA to establish 

maximum reassessment intervals, and to require shorter reassessment 

intervals as conditions warrant. 

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

generally agreed with the report’s findings. The Department of Energy had 

no comments. 

10In-line inspection involves running a specialized tool through a pipeline to detect and 

record anomalies, such as metal loss and damage. 

11Direct assessment and confirmatory direct assessment involve using above-ground 

detection instruments, and then excavating suspected problem areas. 
Page 7 GAO-06-945 Pipeline Reassessment Requirements

Background The United States has about a 295,000-mile network of gas transmission 

pipelines that are owned and operated by approximately 900 operators. 

These pipelines are important to the nation because they transport nearly 

all the natural gas used, which provides about a quarter of the nation’s 

energy supply. Pipelines do not experience many of the safety threats faced 

by other forms of freight transportation because they are mostly 

underground; but they are subject to failures that occur over time—such as 

leaks and ruptures resulting from corrosion12 or welding defects—and 

failures that are independent of time—such as damage from excavation, 

land movement, or incorrect operation. 

For the most part, two types of pipelines transport gas products: (1) gas 

transmission pipelines and (2) local distribution pipelines. Gas 

transmission pipelines typically move gas products over long distances 

from sources to communities and are primarily interstate. They typically 

operate at a higher stress level (higher operating pressure in relation to 

wall strength). By contrast, local distribution pipelines receive gas from 

transmission pipelines and distribute it to commercial and residential end 

users. Local distribution pipelines, which are primarily intrastate, typically 

operate under lower-stress conditions. Local distribution companies may 

also operate small portions of transmission pipelines—typically under 

lower stress—and are therefore subject to the assessment and 

reassessment requirements of the Pipeline Safety Improvement Act of 

2002.13

Before the 2002 act, operators were subject to PHMSA’s minimum safety 

standards for the design, construction, testing, inspection, operation, and 

maintenance of gas transmission pipelines; these standards are applied to 

all pipelines. However, this approach does not account for differences in 

the kinds of threats and the degrees of risk that pipelines face. For 

example, pipelines located in the Pacific Northwest are more susceptible to 

damage from geologic hazards, such as land movement, than pipelines in 

some other areas of the country; but PHMSA’s safety standards do not take

12The Federal Highway Administration estimates the average annual cost of corrosion to gas 

and hazardous liquid transmission pipelines at $7 billion for, among other things, 

maintenance and failures. See Federal Highway Administration, Tech Brief: Corrosion Costs 

and Preventive Strategies in the United States, study performed by CC Technologies, 

March 2002.

13Gas transmission pipeline operators and local distribution companies also operate 

medium-stress pipelines. 
Page 8 GAO-06-945 Pipeline Reassessment Requirements

these threats into account in a systematic way.14 By contrast, the risk-based 

approach of the 2002 act—called the integrity management approach—

requires pipeline operators to develop programs to systematically identify 

threats and mitigate risks to gas transmission pipeline segments located in 

highly populated or frequently used areas.15 In addition to PHMSA’s 

integrity management program, operators must still meet the minimum 

safety standards.

As of December 2005 (latest data available), 447 gas pipeline operators 

reported to PHMSA that about 20,000 miles of their pipelines (about 7 

percent of all gas transmission pipeline miles) lie in highly populated or 

frequently used areas. Individual operators reported that they have as many 

as about 1,600 miles and as few as 0.02 miles of transmission pipeline in 

these areas. 

Under PHMSA’s regulations, gas pipeline operators may use any of three 

primary approaches to conduct baseline assessments on pipeline segments 

lying in highly populated or frequently used areas. 

• In-line inspection: In-line inspection involves running a specialized 

tool through the pipeline to detect and record anomalies, such as metal 

loss and damage. In-line inspection allows operators to determine the 

nature of any problems without either shutting down the pipeline for 

extended periods or potentially damaging the pipeline, as in hydrostatic 

testing (described below). In-line inspection devices can be run only 

from facilities established for launching and retrieving them. These 

launching and retrieval locations may extend beyond highly populated 

or frequently used areas. Operators will typically gather information 

along the entire distance between launching and retrieval locations to 

gain additional safety information; this is called over-testing. 

14Under its minimum safety standards, PHMSA requires stronger pipelines in more highly 

populated areas. In addition, operators are required to annually evaluate their pipelines for 

population growth, which may cause operators to reduce operating pressure or upgrade 

pipelines. 

15The regulatory definition of highly populated or frequently used area is involved. Some 

examples of these areas are (1) an area with 20 or more buildings that could be affected by a 

pipeline incident; (2) a location where a potential impact of a pipeline rupture contains an 

area or open structure that is occupied by 20 or more people on at least 50 days in a 12-

month period (e.g., a camp site); and (3) a facility occupied by persons that would be 

difficult to evacuate, such as a hospital. 
Page 9 GAO-06-945 Pipeline Reassessment Requirements

• Direct assessment: Direct assessment is a nonintrusive, above-ground 

instrument inspection that uses two or more types of diagnostic tools, 

such as a close interval survey, at predetermined intervals along the 

pipeline.16 Once the data are analyzed, the operator excavates and 

inspects segments of the pipeline suspected to have safety threats. 

• Hydrostatic testing: Hydrostatic testing entails sealing off a portion of 

the pipeline, removing the gas product, filling it with water, and 

increasing the pressure of the water above the rated strength of the 

pipeline to test its integrity. If the pipeline leaks or ruptures, the pipeline 

is excavated to determine the cause of the failure. Operators must shut 

down pipelines to perform hydrostatic testing. Also, this form of testing 

can damage the pipeline due to high pressure testing. Finally, operators 

must be able to dispose of large quantities of water in an 

environmentally responsible manner.

Under PHMSA’s regulations, which incorporate voluntary industry 

consensus standards for managing the system integrity of gas pipelines,17

operators must reassess their gas transmission pipeline segments for safety 

threats overall at least every 10, 15, or 20 years (consistent with industry 

consensus standards), depending on the condition of the pipelines and the 

stress under which the pipeline segments are operated. PHMSA’s 

regulations allow operators to limit the statutorily required 7-year 

reassessment to corrosion damage. In performing reassessments to meet 

the 7-year requirement, operators may employ a technique called 

confirmatory direct assessment. This technique is similar to direct 

assessment; however, operators are required to use only one type of 

assessment tool, rather than at least two types required under direct 

assessment. According to PHMSA, it allowed this more limited assessment 

because the 7-year reassessment for corrosion confirms the acceptable 

integrity of a gas transmission pipeline, already ensured by assessments 

and reassessments for safety threats conducted at 10-, 15-, or 20-year 

16A close interval survey is used to assess the coating of covered pipelines for corrosion 

damage.

17Standards 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. For more 

details about industry consensus standards, see the National Association of Corrosion 

Engineers: Standard Recommended Practice – Pipeline External Corrosion Direct 

Assessment (NACE RP002-2002) and the American Society of Mechanical Engineers: 

Managing the System Integrity of Gas Pipelines (ASME B31.8S-2004). 
Page 10 GAO-06-945 Pipeline Reassessment Requirements

intervals under the industry consensus standards incorporated in the 

agency’s regulations. (See fig. 2.) About 2010, operators will be expected to 

begin reassessing some segments of their pipelines for corrosion under the 

7-year reassessment requirement while they are completing baseline 

assessments of other segments—called “the overlap.” 

Figure 2: Reassessments Every 7 Years for Corrosion Supplement Broader Periodic 

Reassessments

Note: Periodic reassessments occur at least every 10, 15, or 20 years. Both periodic and 7-year 

reassessments are supposed to occur more frequently if conditions warrant. 

It is important to note that the reassessment intervals under the industry 

consensus standards, the 7-year reassessment requirement for corrosion, 

and PHMSA’s regulations for time-dependent threats represent the 

maximum number of years between reassessments. If pipeline conditions 

dictate more frequent reassessments—for example, 5 or fewer years—then 

pipeline operators must do so to comply with PHMSA’s regulations.18 In 

addition, between reassessments, operators must continually ensure that 

their gas transmission pipelines are safe. PHMSA’s regulations require all 

operators—whether or not they are located in highly populated or 

frequently used areas to patrol their pipelines, survey for leakage, maintain 

valves, ensure that corrosion-preventing cathodic protection is

18Pipeline conditions and threats change over time. For example, housing may be built 

around pipelines, possibly increasing the threat of excavation damage. Another example is 

that over time the quality of the gas being shipped through the pipeline may change and may 

be more corrosive.

2003 20XX 

Ongoing prevention and mitigation actions

Baseline assessments

(most risky less risky) 

Periodic reassessments for all safety threats

Source: GAO. 

2012 

Reassessments every 7 years for corrosion risks
Page 11 GAO-06-945 Pipeline Reassessment Requirements

working properly,19 and take prevention and mitigation measures to 

prevent excavation damage.

PHMSA, within the Department of Transportation, attempts to ensure the 

safe operation of pipelines through regulation, industry 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 people in its 

pipeline safety program, about half of whom are pipeline inspectors who 

inspect operators’ implementation of integrity management programs for 

gas and hazardous liquid (e.g., oil, gasoline, and anhydrous ammonia) 

pipelines, in addition to other more traditional compliance programs. 

PHMSA currently has 22 inspectors trained to conduct integrity 

management inspections, of which 9 are devoted exclusively to the 

program. In addition, PHMSA expects to be assisted by about 180 

inspectors in 46 states and the District of Columbia in overseeing intrastate 

natural gas transmission pipelines. 

The 7-Year 

Reassessment 

Requirement Appears 

to Be Conservative

Periodic reassessments of pipeline threats are beneficial because threats—

such as the corrosive nature of the gas being transported—can change over 

time. Baseline assessment findings conducted to date and the generally 

safe condition of gas transmission pipelines suggest that the 7-year 

requirement appears to be conservative. Most operators of gas 

transmission pipelines reported to PHMSA that their baseline assessments 

have disclosed 340 problems for which immediate repairs have been made. 

This is encouraging because these pipeline segments are supposed to be 

the riskiest and few have been systematically assessed until now. 

Regarding the industry safety record, the industry is generally safe and no 

corrosion-related incidents resulting in deaths or injuries have occurred in 

the past 5-1/2 years (from January 2001 through early July 2006) anywhere 

in the nation, let alone in highly populated or frequently used areas.20 It is 

therefore likely to be safe in most cases to allow longer maximum

intervals that coincide with industry consensus standards. PHMSA and 

state pipeline agencies plan to inspect all operators’ integrity management 

19Cathodic protection involves a small electrical voltage between a structure and the ground 

to control corrosion.

20As noted earlier, an average of three people have died and eight have been injured over a 

10 1/2-year period, from all causes of natural gas transmission pipeline incidents.
Page 12 GAO-06-945 Pipeline Reassessment Requirements

activities, which should serve as a safeguard if longer reassessment 

intervals for corrosion are permitted. 

Most Operators Have 

Reported That Their Gas 

Transmission Pipelines Are 

Mostly Free of Serious 

Problems

Through December 2005 (latest data available), 76 percent of the operators 

(182 of 241) reporting baseline assessment activity to PHMSA told the 

agency that their gas transmission pipelines were in good condition and 

free of major defects, requiring only minor repairs. (These assessments 

covered about 6,700 miles, or about one-third of the nationwide total to be 

assessed). The remaining 59 operators reported 340 problems for which 

immediate repairs have been completed. (See fig. 1.)

Fifty-two operators (21 percent) reported nine or fewer problems for which 

immediate repairs have been completed; and seven operators (3 percent) 

reported 10 or more problems. Most of the problems stem from the seven 

operators reporting 10 or more problems and concern only a small portion 

of their gas transmission pipelines. Specifically, these seven operators 

represent nearly 60 percent of the total problems requiring immediate 

repairs, and the problems occurred in only 7 percent of 6,700 miles of 

baseline assessments conducted.21 Since PHMSA does not require that 

operators report to it the nature of the problems, we do not know how 

many of the 340 problems, if any, were due to corrosion. 

We contacted 52 operators about the baseline assessments they have 

completed and their plans for the rest, and the results were largely 

consistent with the overall data reported to PHMSA. Forty-four of these 

operators have begun baseline assessments, and 37 of these 44 (84 percent) 

told us that they found few safety problems that required reducing pipeline 

pressure and performing immediate repairs in response to baseline 

assessments in highly populated or frequently used areas. These 44 

operators have assessed about 4,100 miles of gas transmission pipeline, 

representing about 61 percent of the 6,700 miles of baseline assessment 

results reported to PHMSA and about 21 percent of the total number of 

pipeline miles in highly populated or frequently used areas nationwide.

It is encouraging that the majority of operators nationwide reported few or 

no problems involving immediate repairs, because (1) operators are to 

assess pipeline segments facing the greatest risk of failure from leaks or 

21As noted earlier, product flow and pipeline capacity can be useful to understand the extent 

of problems and their effect. However, this measurement was not practical. 
Page 13 GAO-06-945 Pipeline Reassessment Requirements

ruptures first, as required by the 2002 act, and (2) 54 percent of the 

operators we contacted (28 of 52) had not conducted risk-based 

assessments of their pipeline segments for safety threats prior to the 

integrity management program. 

Although the PHMSA regulations focus the 7-year reassessment 

requirement on corrosion because it is the most frequent cause of timedependent pipeline incidents,22 the industry has had a good safety record 

prior to and during the initial years of integrity management. It is not 

possible to determine which incidents occurred in highly populated or 

frequently used areas from summary historical data published by PHMSA. 

However, nationwide, these incidents are relatively rare. Over the past 51⁄2 

years (from January 2001 through early July 2006), there were 143 

corrosion-related incidents over the 295,000-mile transmission system (26 

per year, on average)—none of which resulted in death or injury. In 

addition, according to PHMSA, during the first 2 years of integrity 

management (2004 and 2005), operators reported that corrosion caused 49 

leaks,23 16 failures, and two incidents involving significant property 

damage, but no fatalities and injuries, in highly populated or frequently 

used areas. 

Both the positive results found during baseline assessments conducted to 

date and the overall good safety industry record suggest that gas 

transmission pipeline operators that have thus far performed baseline 

assessments overall are doing a good job in managing corrosion. Further, 

since operators, are required to identify and repair significant problems, 

the overall safety and condition of the gas transmission pipeline system 

should be enhanced before reassessments begin toward the end of the 

decade. 

22Third-party damage is a significant cause of gas transmission pipeline incidents. In 

addition, third-party damage can cause pipeline dents that may lead to corrosion.

23Leaks from gas transmission pipelines can allow methane to escape into the atmosphere. 

Methane is a potent greenhouse gas that contributes to climate change. See U.S. 

Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990-2003, April 2005.
Page 14 GAO-06-945 Pipeline Reassessment Requirements

Operators Support Baseline 

Assessments and 

Reassessments but Prefer a 

Risk-based Reassessment 

Requirement Over a Fixed 

One

Because many gas transmission pipelines had never been assessed before 

integrity management, operators we contacted pointed out that the new 

knowledge gained through baseline assessments represents one of the 

greatest benefits of the integrity management program. They also support 

reassessments, in part because all operators are subject to the same 

requirements. However, most support a risk-based reassessment 

requirement, consistent with overall integrity management, over the fixed 

7-year requirement prescribed by the 2002 act. Operators also told us they 

prefer a risk-based reassessment requirement that is based on research and 

historical information. Most operators told us they prefer reassessing 

pipelines based on the characteristics and conditions of the pipeline rather 

than on the 7-year requirement prescribed in the 2002 act. About 80 percent 

of the 52 operators that we contacted prefer that reassessment intervals be 

based on the condition and characteristics of the pipeline segment. About 

half of these operators (28) expressed a preference for the industry 

consensus standard developed by the American Society of Mechanical 

Engineers (ASME B31.8S-2004) for setting reassessment intervals for timedependent threats because it incorporates a risk-based approach (for 

pipeline failure) and is based on science and engineering knowledge. This 

standard sets reassessment intervals at a maximum of 10 years for highstress pipeline segments, 15 years for medium-stress segments, and 20 

years for low-stress segments. Maximum reassessment intervals, such as 

those in the industry consensus standard, incorporate such risk concepts 

as built-in safety factors (e.g., wall stress, test pressure, or predicted 

failure) and pipeline conditions. The maximum intervals of 10, 15, and 20 

years are based on worst-case corrosion growth rates. 

The industry consensus standards were developed in 2001 and updated in 

2004 based on, among other things, (1) the experience and expertise of 

engineers, consultants, operators, local distribution companies, and 

pipeline manufacturers; (2) more than 20 technical studies conducted by 

the Gas Technology Institute, ranging from pipeline design factors to 

natural gas pipeline risk management; and (3) other industry consensus 

standards, including the National Association of Corrosion Engineers 

standards, on topics such as corrosion. Contributors have been practicing 

aspects of risk-based assessments for over 10 years. This standard serves 

as a foundation for most sections of PHMSA’s integrity management 

regulations. The mechanical engineering society’s standard was reviewed
Page 15 GAO-06-945 Pipeline Reassessment Requirements

by the American National Standards Institute.24 The institute found that the 

standard was developed in an environment of openness, balance, 

consensus, and due process and therefore approved it as an American 

National Standard. 

While the mechanical engineering standards are voluntary for the industry, 

PHMSA incorporated them as mandatory in its gas transmission integrity 

management regulations. The mechanical engineering society’s standard 

for setting reassessment intervals is not the only industry consensus 

standard in PHMSA’s integrity management regulations. The regulations 

incorporate other industry consensus standards for using direct 

assessment for corrosion, calculating pipeline wall strength, and for 

determining temporary reductions in operating pressure. In addition, it is 

federal policy to encourage the use of industry consensus standards: the 

Congress expressed a preference for technical standards developed by 

consensus bodies over agency-unique standards in the National Technology 

Transfer and Advancement Act of 1995. The Office of Management and 

Budget’s Circular A-119 provides guidance to federal agencies on the use of 

voluntary consensus standards, including the attributes that define such 

standards. 

Of the 52 operators we contacted, 44 had undertaken baseline assessments, 

and 23 of the 44 have calculated their own reassessment intervals.25 Twenty 

of these 23 operators indicated that, based on the conditions they identified 

during their baseline assessments, they would reassess their gas 

transmission pipelines at maximum intervals of 10, 15, or 20 years—as 

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

requirement were not in place. The remaining three operators told us that 

they would reassess their pipelines at intervals shorter than the industry 

consensus standards but longer than 7 years because of the conditions of 

their pipelines. These results add weight to our assessment that the 7-year 

requirement may be conservative for most pipelines. 

24The American National Standards Institute is a private, nonprofit 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. 

25The other 21 operators (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 with information on their reassessment intervals. 
Page 16 GAO-06-945 Pipeline Reassessment Requirements

Safeguards Exist if Industry 

Consensus Standards for 

Corrosion Reassessments 

Are Allowed

Industry consensus standards allow for maximum reassessment intervals 

for time-dependent threats of 10, 15, or 20 years only if the operator can 

adequately demonstrate that corrosion will not become a threat within the 

chosen time interval. If an operator cannot demonstrate that corrosion 

does not pose a threat, (e.g., threats posed by shipping gas that is more 

corrosive then was shipped previously), then the reassessment must occur 

sooner, perhaps at 7 or even 5 or fewer years. Furthermore, according to 

industry consensus standards, it typically takes longer than the 10, 15, or 20 

years specified in the standard for corrosion problems to result in a leak or 

rupture. 

As a means of ensuring that assessments and reassessments are done 

competently, PHMSA regulations and industry consensus standards require 

that operators develop and document the steps they take to ensure the 

quality of these activities. This includes ensuring that persons involved are 

competent and able to carry out the activities. In addition, operators are 

encouraged to conduct internal audits of their quality control approaches 

and third-party reviews of their entire integrity management programs.

It is important to note that, in addition to periodic reassessments, operators 

must perform prevention and mitigation activities on a continual basis. 

PHMSA regulations require that all operators of gas transmission pipelines, 

including those outside highly populated or frequently used areas, patrol 

their pipelines, survey for leakage, maintain valves, ensure that corrosionpreventing cathodic protection is working properly, and take other 

prevention and mitigation measures. 

Finally, PHMSA and the state pipeline agencies are inspecting operators’ 

integrity management plans that were mandated by the 2002 act to provide 

their gas transmission pipeline reassessment approaches and intervals, 

among other things, to ensure that operators continually and appropriately 

assess the conditions of their pipeline segments in highly populated or 

frequently used areas. These inspections should serve as a check on 

whether operators have identified threats facing these pipeline segments 

and determined appropriate reassessment intervals. PHMSA and states 

have begun inspections and expect to complete most of the first round no 

later than 2009. As of June 2006, PHMSA had completed 20 of about 100 

inspections and, as of January 2006, states had begun or had completed 117
Page 17 GAO-06-945 Pipeline Reassessment Requirements

of about 670 inspections.26 Initial results from these inspections show that 

operators are doing well in assessing their pipelines and making repairs, 

but some need to better document their programs. Based on the initial 

inspection results to date, PHMSA and states did not find many issues that 

warranted enforcement actions.

Sufficient Resources 

May Be Available for 

Pipeline 

Reassessments

Although some uncertainty exists, sufficient resources may be available for 

operators to reassess their gas transmission pipelines. 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. However, operators expressed their uncertainty about whether 

qualified direct assessment and confirmatory direct assessment 

contractors will be available. This is important because operators plan to 

use these methods to reassess about half of their pipeline mileage. 

Contractors told us that they will likely have the capacity to meet demands, 

even during periods when baseline assessments and reassessments may 

overlap. The severity of this overlap, however, remains unclear. Although 

operators that we contacted expect baseline assessment and reassessment 

activity to decrease from 2010 through 2012, an Interstate National Gas 

Association of America (INGAA) and American Gas Association (AGA) 

polling of their members suggests that activity will rise markedly.27

26See GAO-06-946 for additional information on the results of PHMSA and state inspections. 

27INGAA represents the natural gas industry, including transmission pipeline operators. 

According to INGAA, it represents virtually all of the interstate natural gas transmission 

pipeline companies operating in the United States. Its members transport over 95 percent of 

the nation's natural gas. AGA represents local energy utility companies, including pipeline 

companies, which deliver natural gas to homes, businesses, and industries throughout the 

United States. According to AGA, its members account for roughly 83 percent of all natural 

gas delivered by the nation's local natural gas distribution companies.
Page 18 GAO-06-945 Pipeline Reassessment Requirements

Operators Report that 

Services and Tools Are 

Likely to Be Available for 

Reassessments

Thirty-seven out of 52 operators (71 percent), one in-line inspection 

association, and all four inspection contractors that provide direct 

assessment or in-line inspection tool services that we contacted told us that 

the services and tools needed to conduct periodic reassessments will likely 

be available to most operators.28 All but 3 of the operators reported that 

they plan to rely on contractors to conduct all or a portion of their 

reassessments, and 9 of 52 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 

they are several years in the future and operators are concentrating on 

baseline assessments.

The 48 operators that reported both baseline and reassessment schedules 

told us that they plan to reassess 42 percent of their gas transmission 

pipeline miles in highly populated or frequently used areas, using in-line 

inspection, and 54 percent of their miles using direct assessment or 

confirmatory direct assessment methods.29 (See fig. 3.) Operators expect 

to assess only 4 percent of their pipeline miles using hydrostatic testing for 

several reasons: (1) this form of testing requires shutting down their 

pipelines, (2) other assessment methods yield more robust information 

about the condition of their pipelines, (3) hydrostatic testing can weaken or 

damage pipelines, and (4) large quantities of water must be disposed of in 

an environmentally responsible manner. 

28We contacted the Inline Inspection Association, two companies offering in-line inspection 

services, and two companies offering direct assessment services. In our assessment of the 

public safety effects of integrity management, we reported that 94 percent of the operators 

we contacted had no major concerns about their ability to complete baseline assessments. 

(See GAO-06-946.) The difference in these findings may be due to the fact that operators 

have 10 years to complete baseline assessments but must reassess pipeline segments every 

7 years or in a shorter period if conditions warrant. The shorter reassessment period could 

heighten demand for inspection services and tools. 

29Some operators we contacted reported that the cost of using confirmatory direct 

assessment as compared with other assessment tools and the limited time savings before 

conducting a full assessment as reasons for not planning to use this method. 
Page 19 GAO-06-945 Pipeline Reassessment Requirements

Figure 3: Operators Contacted Plan to Reassess Nearly All of the Mileage in Highly 

Populated or Frequently Used Areas Using In-line Inspection and Direct Assessment 

Tools 

Note: Some operators may use one type of assessment tool on one portion of their gas transmission 

pipeline and another type of assessment tool on another portion.

The Inline Inspection Association and the two in-line inspection 

contractors that we contacted told us that sufficient capacity exists within 

the industry to meet current and future operator demands. However, 

operators and inspection contractors expressed uncertainty about whether 

qualified direct assessment and confirmatory direct assessment 

contractors will be available. This is important because operators plan to 

use these methods to reassess about half of their gas transmission pipeline 

mileage. Unlike the in-line inspection method, which is an established and 

less intrusive practice that 27 of 52 operators have used on their pipelines 

at least once prior to the integrity management program, two direct 

assessment contractors told us that there is limited expertise in this field. 

One 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 generally those with smaller-diameter pipelines that

24% 

30% 

42% 

Source: GAO discussions with 48 operators.

4% 

Hydrostatic testing 

In-line inspection

Direct assessment

Confirmatory direct assessment 
Page 20 GAO-06-945 Pipeline Reassessment Requirements

cannot accommodate in-line inspection tools.30 At a recent INGAA integrity 

management workshop, in-line inspection and direct assessment 

inspection contractors emphasized that, although they currently have the 

resources to meet operator demand and continue to train new inspectors, 

operators need to plan ahead to ensure resource availability for future 

years, when resources may be more constrained. The workshop also 

highlighted technological developments for assessment tools that will 

make assessments more efficient. Other stakeholders have told us that 

there are new tools being developed that will enable smaller-diameter 

pipelines to accommodate in-line inspection tools. For example, the 

Department of Energy is developing tiny robotic sensors that can detect 

flaws in plastic natural gas pipelines without interrupting the flow of gas.

The Amount of Assessment 

Activity Occurring in the 

Overlap Period Is Uncertain 

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

operators will be required to conduct reassessments starting no later than 

2010, while they are still in the 10-year period (2003 through 2012) for 

conducting baseline assessments. Industry is concerned that this could 

create a spike in demand for contractor services, and operators would have 

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

result, operators might not be able to meet the reassessment requirement.31 

The information provided by the operators that we contacted shows a 

marked overall increase in assessment and reassessment activity in 2010 (a 

16 percent increase over 2009 activity) and then a gradual decrease of 

activity through 2012. (See fig. 4.) Operators expect this decrease because 

they plan to have completed 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 (3 

years before the predicted overlap).

30According to industry estimates, 35 percent of all local distribution company pipelines (as 

measured in miles likely to be located in highly populated or frequently used areas) cannot 

accommodate an in-line inspection tool, compared with only about 4 percent of 

transmission operators’ pipelines.

31The 2002 act allows operators to request a waiver from conducting reassessments when 

inspection tools are not available. PHMSA regulations require that operators apply for a 

waiver when inspection tools are not available to conduct assessments within the required 

reassessment period and that the actions the operator is taking in the interim ensures the 

integrity of the pipeline. Environmental requirements may also affect the scheduling of 

assessments, repairs and modifications, and the choice of assessment tools. (See app. I.) 

Few of the 52 operators that we contacted mentioned this as a concern.
Page 21 GAO-06-945 Pipeline Reassessment Requirements

Figure 4: Baseline Assessment and Reassessment Activities Are Expected to Decrease during the Overlap Period, According to 

Operators We Contacted

Note: These results are based on information obtained from 47 of 52 operators we contacted, covering 

154,000 miles of gas transmission pipeline, 12,000 miles of which are in highly populated or frequently 

used areas. Five operators did not report their reassessment plans. We did not ask operators to 

separate baseline assessments and reassessments in areas that are not highly populated or 

frequently used. 

In contrast, INGAA and AGA, after polling their members in 2006, found a 

steady overall increase in total expected baseline assessments and 

reassessments during the overlap period. INGAA and AGA found that 

baseline assessments and reassessments would start to increase in 2009 

and rise steadily through 2012.32 (See fig. 5.) Assessment activity would 

Miles assessed

Year

Non-HCA

Reassessments

Baseline assessments

Source: GAO discussions with 52 operators.

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

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

32Although INGAA, AGA, and we collected information differently on the extent that 

baseline assessments and reassessments would be conducted inside and outside highly 

populated or frequently used areas, both efforts collected information on overall baseline 

assessment and reassessment activity. As a result, the overall results of both efforts are 

comparable and are shown in figure 6.
Page 22 GAO-06-945 Pipeline Reassessment Requirements

increase by 5 percent in 2010 over the 2009 level; in 2011, by 8 percent over 

the preceding year; and in 2012, by 10 percent over the 2011 level.

Figure 5: Baseline and Reassessment Activities Are Expected to Increase during the Overlap Period, According to INGAA and 

AGA

Note: These results are based on responses from 56 operators covering 180,000 miles of gas 

transmission pipeline, 11,000 miles of which are in frequently used or highly populated areas.

The difference between our findings and those of INGAA and AGA is not 

easy to explain. (See fig. 6.) Both efforts reported on comparable numbers 

of operators (47 for us and 56 for INGAA/AGA) and total transmission 

pipeline miles (154,000 for us and 180,000 for INGAA/AGA). To some 

extent, the difference may be due to the variations in the pipeline operators 

that responded to both efforts. About 72 percent of operators we polled 

were different from those polled by INGAA and AGA. However, even where 

both efforts collected information from the same operators, the 

information was sometimes markedly different. Another reason for the 

difference may be due to methodology. For example, we gathered our 

information through semistructured interviews with a systematically 

Miles assessed 

Year 

Reassessments

Baseline assessments

Source: GAO analysis of INGAA and AGA results. 

0 

2,000 

4,000 

6,000 

8,000 

10,000 

12,000 

14,000 

16,000 

Pre 2003 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 
Page 23 GAO-06-945 Pipeline Reassessment Requirements

selected set of pipeline operators based on larger and smaller transmission 

pipelines and local distribution companies with the highest proportion of 

pipeline miles in highly populated or frequently used areas to total system 

miles, among other things. INGAA and AGA gathered their information by 

sending out a self-administered data collection instrument to their 

members, and reported results based on those members who responded. In 

addition, INGAA and AGA asked operators for data somewhat differently 

from methods we used, which may have led to some differences in results.

Figure 6: GAO and INGAA/AGA Results Show Different Trends in Assessment Activity during the Overlap Period

Note: See text for possible reasons for the difference in results. Readers should not interpret these 

results to suggest that operators are not planning to complete all required baseline assessment 

activities by the end of 2012. 

Conclusions Evidence as a result of baseline assessments, the industry’s overall safety 

record, the existence of accepted risk-based assessment standards, and 

PHMSA’s actions to inspect how operators are identifying corrosion threats 

to their pipelines and setting reassessment intervals suggests a risk-based 

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

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

Miles of pipeline

Sources: GAO discussions with 52 operators and GAO analysis of INGAA/AGA results.

Year 

GAO 

INGAA/AGA 
Page 24 GAO-06-945 Pipeline Reassessment Requirements

approach to reassessing gas transmission pipeline segments for corrosion 

can achieve the safety objectives of the 2002 act. Evidence gathered to date 

suggests that operators that have thus performed baseline assessments are 

doing a good job overall managing corrosion. Since the large majority of 

pipeline operators that we contacted had not systematically assessed their 

transmission pipelines for corrosion risks before the onset of the gas 

integrity management program, if corrosion were a rapidly growing 

problem, we would have expected a larger proportion of pipelines to report 

problems requiring immediate repairs. But, this was not the case. 

Furthermore, adopting a risk-based approach to setting reassessment 

intervals does not automatically allow operators to reassess their pipeline 

segments less frequently than under the 7-year requirement. Rather, if 

conditions warrant, an operator would be required to reassess a pipeline 

segment as frequently as needed—perhaps even more frequently than 

every 7 years. Finally, a risk-based reassessment requirement would be 

consistent with the overall approach to integrity management that the 

Congress put in place with the 2002 act. 

Safeguards are in place to ensure that gas transmission operators 

determine reassessment intervals competently. PHMSA regulations and 

industry consensus standards require that operators ensure that persons 

involved have the experience and expertise to carry out the activities. 

Operators are also encouraged to conduct internal audits of their quality 

control approaches and third-party reviews of their integrity management 

programs. PHMSA and the state pipeline agencies are inspecting operators’ 

compliance with integrity management reassessment requirements, among 

other things, to ensure that operators continually and appropriately assess 

the conditions of their gas transmission pipeline segments in highly 

populated or frequently used areas. 

In summary, the available evidence supports a conclusion that a risk-based 

reassessment approach based on technical data, risk factors, and 

engineering analyses can achieve the 2002 act’s safety objectives. Such an 

approach would provide for reassessments to be tailored to the corrosion 

threats faced by the pipeline segment and would not result in 

reassessments that are either too infrequent or premature. Evidence to 

date suggests that gas transmission pipelines are generally in good shape 

based on assessments, following up with immediate repairs and safeguards 

being in place to ensure operators determine reassessments appropriately. 

In our view, it is not necessary to wait until baseline assessments and a 

round of reassessments have been completed before considering whether 

to retain or modify the 7-year reassessment requirement. 
Page 25 GAO-06-945 Pipeline Reassessment Requirements

Matter for 

Congressional 

Consideration

To better align reassessments with safety risks, the Congress should 

consider amending section 14 of the Pipeline Safety Improvement Act of 

2002 to permit pipeline operators to reassess their gas transmission 

pipeline segments at intervals based on technical data, risk factors, and 

engineering analyses. Such a revision would allow PHMSA to establish 

maximum reassessment intervals, and to require shorter reassessment 

intervals as conditions warrant. 

Agency Comments and 

Our Evaluation

We provided a draft of this report to the Departments of Transportation and 

Energy for their review and comment. The Department of Transportation 

generally agreed with the report’s findings. The Department of Energy had 

no comments. 

We are sending copies of this report to congressional committees and 

subcommittees with responsibility for transportation safety issues; the 

Secretary of Transportation; the Secretary of Energy; the Administrator, 

PHMSA; the Assistant Administrator and Chief Safety Officer, PHMSA; the 

Deputy Secretary for Natural Gas and Petroleum Technology, Department 

of Energy; and the Director, Office of Management and Budget. We will also 

make copies available to others upon request. This report will be available 

at no charge on the GAO Web site at http://www.gao.gov. 

If you have any questions about this report, please contact me at (202) 512-

2834 or siggerudk@gao.gov. Contact points for our Offices of Congressional 

Relations and Public Affairs may be found on the last page of this report. 

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

Katherine A. Siggerud

Director, Physical Infrastructure Issues
Page 26 GAO-06-945 Pipeline Reassessment Requirements

Congressional Committees

The Honorable Ted Stevens

Chairman

The Honorable Daniel K. Inouye

Co-Chairman

Committee on Commerce, Science

and Transportation

United States Senate

The Honorable Don Young

Chairman

The Honorable James L. Oberstar

Ranking Democratic Member

Committee on Transportation

and Infrastructure

House of Representatives

The Honorable Joe Barton

Chairman

The Honorable John D. Dingell

Ranking Minority Member

Committee on Energy and Commerce

House of Representatives
Page 27 GAO-06-945 Pipeline Reassessment Requirements

Appendix I

Impact of Periodic Reassessments on Natural Apendxies

Gas Supply May Be Less than Foreseen ApendxiI

As the Pipeline Safety Improvement Act of 2002 was being considered, the 

Interstate Natural Gas Association of America (INGAA) analyzed the 

possible impact of requiring assessments and periodic reassessments and 

found that significant disruptions in the natural gas supply and 

considerable price increases could occur.1

 A more moderate impact was 

predicted in three subsequent analyses—(1) two reviews of the INGAA 

study performed for the Pipeline and Hazardous Materials Administration 

(PHMSA) by the John A. Volpe National Transportation Systems Center and 

by the Department of Energy during the congressional debate over the 

pipeline bill, and (2) a post-act PHMSA evaluation of its implementing 

regulations.2

 A waiver provision was included in the 2002 act after INGAA’s 

study was completed; this may serve as a safety valve if it appears that the 

natural gas supply may be disrupted. Finally, our discussions with 50 

natural gas pipeline operators also suggest a more moderate potential 

impact than INGAA found. 

INGAA Study Expected 

Significant Supply 

Disruptions and Price 

Increases

INGAA’s study estimated that periodic assessments under integrity 

management could lead to a monthly reduction in natural gas supply of 

about 1 to 3 percent, along with price increases to customers, among 

others, ranging from $382 million to over $1 billion (in 2002 dollars) from 

2002 through 2010, depending on the frequency of assessments.3

 Most of 

this price increase would be due to supply disruption and some due to 

capital expenditures. INGAA considered the monthly reduction in supply to 

be significant because it assumed that gas transmission pipelines would be 

1

Prepared for The INGAA Foundation, Inc., by Energy and Environmental Analysis, Inc., 

Consumer Effects of the Anticipated Integrity Rule for High Consequence Areas, 2002. 

2

See, Department of Transportation docket, RSPA-00-7666, Energy Impact Statement for 

Pipeline Integrity Management in High Consequence Areas (Gas Transmission 

Pipelines), March 28, 2002, prepared by John A. Volpe National Transportation Systems 

Center and the U.S. Department of Transportation; Comments from U.S. Department of 

Energy on INGAA’s Consumer Effects of the Anticipated Integrity Rule for High 

Consequence Areas, April 2, 2002; and Research and Special Programs Administration, 

Final Regulatory Evaluation, Pipeline Integrity Management in High Consequence Areas 

(Gas Transmission Pipelines), March 28, 2002.

3

The National Petroleum Council also discussed the supply effects of the integrity 

management program, including that some pipelines may be removed from service if it is 

not economically efficient to repair them. The council did not estimate the extent that these 

abandonments might occur or the resulting price increases, if any. See Balancing Natural 

Gas Policy: Fueling the Demands of a Growing Economy Volume V, Transmission and 

Distribution Task Group and LNG Subgroup Report, September 2003.
Appendix I

Impact of Periodic Reassessments on Natural 

Gas Supply May Be Less than Foreseen

Page 28 GAO-06-945 Pipeline Reassessment Requirements

removed from service during testing and that some areas of the country 

would be more vulnerable to supply disruptions than others.

PHMSA-commissioned 

Reviews and PHMSA’s 

Regulatory Evaluation 

Predict More Moderate 

Impacts

Both Volpe’s and the Department of Energy’s 2002 reviews of the INGAA 

study concluded that gas transmission pipelines would not be significantly 

affected by periodic assessments. The reviews, however, did not attempt to 

quantify overall estimates of gas disruptions or price impacts. Rather, they 

examined the major assumptions in the INGAA study and discussed 

whether the study’s results seemed reasonable. PHMSA’s final regulatory 

evaluation, which was completed in 2004 to assess the impact of PHMSA’s 

regulations on implementing the 2002 act, concluded that transmission 

pipelines’ natural gas supply may be somewhat disrupted as a result of 

assessments and that cost increases may occur. However, PHMSA 

acknowledged that it could not estimate the impact of assessments on gas 

prices. In general, the reviews found that the INGAA study’s estimates of 

price impacts represent a worst-case scenario because of several overly 

pessimistic assumptions. For example, the INGAA study 

• underestimated the ability of the pipeline network to mitigate

disruptions. INGAA assumed that pipeline assessments would 

generally reduce pipeline capacity temporarily, thereby disrupting the 

supply and increasing the price of natural gas. Yet, both Volpe’s and the 

Department of Energy’s reviews found that the INGAA study did not 

sufficiently account for redundancies in the nation’s natural gas 

transmission pipeline network. Redundancies enable operators to 

mitigate potential disruptions during assessments by rerouting gas 

through the network. 
Appendix I

Impact of Periodic Reassessments on Natural 

Gas Supply May Be Less than Foreseen

Page 29 GAO-06-945 Pipeline Reassessment Requirements

Operators we contacted that have higher-stress gas transmission pipelines4

generally indicated that their pipeline infrastructure is versatile and 

includes such redundancies as parallel pipelines or looping capabilities that 

allow gas to flow to customers while portions of the pipeline are assessed 

or repaired.5

 (See fig. 7.) Operators of lower-stress pipelines6 reported that 

they typically use a set of laterals,7 which feed an interconnected gas 

distribution system and allow them to plan around disruptions. In addition, 

lower-stress operators can use liquid or compressed natural gas that is 

located at their facilities or transported by trucks to specified locations. 

Forty-four of the 50 natural gas operators (88 percent) that we contacted 

have some type of alternative gas supply, such as storage facilities and 

other gas suppliers, to meet customers’ short-term needs.

4

Higher-stress pipelines operate under pressure at or above 50 percent of the pressure that 

will cause a pipeline to deform (called yield strength).

5

A looping capability involves installing a segment of pipeline adjacent to an existing 

pipeline. The segment of pipeline connects to the existing pipeline at both ends of a loop, 

which allows more gas to be moved through the pipeline system.

6

Lower-stress pipelines operate pressure at or below 30 percent of a pipeline’s yield 

strength.

7

A lateral is a segment of a pipeline that branches off of the main or transmission line to 

transport the product to a termination point, such as a tank farm or a metering station.
Appendix I

Impact of Periodic Reassessments on Natural 

Gas Supply May Be Less than Foreseen

Page 30 GAO-06-945 Pipeline Reassessment Requirements

Figure 7: Parallel Natural Gas Transmission Pipelines Can Help Maintain Product 

Supply

Source: PHMSA.
Appendix I

Impact of Periodic Reassessments on Natural 

Gas Supply May Be Less than Foreseen

Page 31 GAO-06-945 Pipeline Reassessment Requirements

• assumed that a large amount of transmission mileage would 

require assessments because of over-testing. The INGAA study 

concluded that the number of gas transmission pipeline miles within 

highly populated or frequently used areas is only about 5 percent of the 

total mileage in the U.S. Nonetheless, the study assumed that over 80 

percent of mainline interstate pipeline miles would require assessing, 

because the pipeline miles that are located within the highly populated 

areas are scattered throughout the pipeline system, and inspection 

methods like in-line testing can only be inserted and retrieved in certain 

locations that may lie outside highly populated or frequently used 

locations. As a result, the study assumed that operators of these 

pipelines would assess over 1,500 percent more miles than are within 

the highly populated areas. On the basis of comments from industry 

groups, PHMSA’s regulatory evaluation assumed that operators would 

assess about 625 percent more miles when using in-line inspection 

testing and about 25 percent more miles when using hydrostatic testing, 

but no over-testing when using the direct assessment method. Baseline 

assessment results to date seem to support the lower over-testing

estimate: as of December 31, 2005, on the basis of performance reports 

submitted to PHMSA, operators assessed about 650 percent more miles 

overall than are located in highly populated or frequently used areas.8

• assumed that only hydrostatic testing would be used on delivery 

laterals. The INGAA study predicted that operators would use only 

hydrostatic testing on lateral gas transmission pipelines because it 

assumed that very few laterals can accommodate in-line testing. Under 

hydrostatic testing, water pressure is used to test the condition of 

pipelines; therefore, all of the capacity of a pipeline segment must be 

removed for a period of time. 

Volpe’s review concluded that this particular assumption represents the 

worst possible impact of assessments on lateral pipelines because it 

does not allow for the use of in-line testing or direct assessment. Based 

on discussions with operators and public comments on PHMSA’s draft 

regulatory analysis, the PHMSA regulatory evaluation also assumed 

that few operators would use hydrostatic testing. INGAA’s study also 

did not address the development of new technologies that could allow 

8

Over-testing, although not without costs, provides safety benefits because additional 

information is collected about the condition of pipelines. The operators’ reports do not 

indicate which inspection method was used to conduct the inspections. 
Appendix I

Impact of Periodic Reassessments on Natural 

Gas Supply May Be Less than Foreseen

Page 32 GAO-06-945 Pipeline Reassessment Requirements

in-line inspection of smaller diameter pipelines. As discussed earlier, 

new technology is being developed. Finally, operators we contacted 

reported that they do not plan to use hydrostatic testing extensively. As 

discussed earlier, only about 4 percent of the mileage will be reassessed 

using hydrostatic testing. This testing will typically be over relatively 

small lengths of pipeline (from 0.8 to 331 miles). 

• did not incorporate the ability of operators to obtain waivers. 

The INGAA study did not consider the possible impact of a waiver 

provision in the 2002 act on maintaining the natural gas supply. This was 

understandable because the waiver provision was added to the bills 

under consideration after the INGAA study was completed. The act 

allows the PHMSA to waive or modify any requirement for operators to 

conduct reassessments when they need to maintain product supply as 

long as it is consistent with pipeline safety.9

 Twenty-one of the 50 natural 

gas operators (42 percent) that we contacted said that they would 

consider applying for a waiver, if needed, and 23 (46 percent) told us 

that they did not plan to apply for a waiver. Three of the operators were 

uncertain, and the remaining three operators did not provide us with a 

response. Fourteen of the 26 operators that either did not plan to apply 

for a waiver or were unsure about doing so said that it is too early to 

determine the need for applying for waivers. They obtained the 

necessary equipment to conduct assessments or developed plans for 

handling potential natural gas supply disruptions.10

9

Under PHMSA’s regulations, an operator must apply for a waiver at least 180 days before 

the required reassessment interval, unless natural gas supply issues make the period 

impractical. If so, the operator must apply as soon as the need for the waiver is known.

10Eleven operators we contacted did not provide reasons for not planning to apply for a 

waiver. One operator reported that it would wait for regulatory changes for reassessments 

before applying for a waiver. 
Appendix I

Impact of Periodic Reassessments on Natural 

Gas Supply May Be Less than Foreseen

Page 33 GAO-06-945 Pipeline Reassessment Requirements

Operators Contacted Found 

Assessments Have Had 

Minimal Impact on Supply

Pipeline operators we contacted told us that assessments and repairs of 

even their riskiest gas transmission pipelines have not significantly 

disrupted the natural gas supplied to customers, such as local distribution 

companies and power plants. These 50 natural gas transmission operators 

and local distribution companies had assessed about 4,100 miles of pipeline 

in highly populated or frequently used areas, as of December 2005 (latest 

data available)—or about 21 percent of the total gas transmission mileage 

in these areas in the nation and about 62 percent of the pipeline mileage 

located in frequently used or highly populated areas assessed to date. Of 

the 44 operators that have begun baseline assessments, 26 (59 percent) 

indicated that their assessments and repairs did not require them to shut 

down their pipelines or reduce their operating pressure. Sixteen operators 

(36 percent) reported minor disruptions in their gas supply because they 

temporarily shut down pipelines and reduced operating pressure to 

conduct assessments or repairs. These operators told us that they used 

alternative gas sources, such as liquefied natural gas, to sustain their 

customers’ gas supply. The remaining two operators (5 percent) were 

located in regions that have limited excess gas capacity. Both operators 

reported that they could not meet all of the natural gas needs of their 

customers when their pipelines were shut down to perform assessments or 

repairs. Some customers, especially those with interruptible contracts,11

did not receive gas from the pipelines for several days, but they were able 

to obtain gas from alternative sources. 

Eleven of the 44 operators were located in regions that have limited excess 

gas capacity—the Northeast, the Rocky Mountains, and the Southwest—

and reported minor supply disruptions. Five of the 11 operators—all of 

which operate lower-stress gas transmission pipelines—reported that none 

of these disruptions in natural gas supply were caused by assessments or 

repairs. Four operators reported instances in which immediate repairs 

caused a reduction in operating pressure; however, they maintained natural 

gas supply by relying on alternative gas sources.12 Since PHMSA does not 

11Although interruptible contracts with pipeline operators or local distribution companies 

vary in terms and conditions, they generally allow for service interruptions that are caused 

by system operating conditions (e.g., when pipeline pressure is threatened by high rates of 

natural gas consumption), among other things.

12We did not ask operators about the degree to which they reduced operating pressure and 

the reduction in the amount of gas that they could deliver. Nevertheless, they were able to 

use alternative sources to maintain product supply while they made repairs to their 

pipelines.
Appendix I

Impact of Periodic Reassessments on Natural 

Gas Supply May Be Less than Foreseen

Page 34 GAO-06-945 Pipeline Reassessment Requirements

require that operators report to it the nature of the problems, we do not 

know how many immediate repairs, if any, were due to corrosion. And, as 

previously mentioned, 2 of the 11 operators reported natural gas supply 

disruptions; although they had to shut down their pipelines due to 

assessments or repairs, customers were able to obtain natural gas from 

other sources. 

In early 2006, INGAA and AGA polled their members about their 

experiences with and plans for conducting assessments and reassessments 

during off-peak and peak months.13 Overall, INGAA and AGA found that, 

from 2003 to 2012, members plan to conduct 76 percent of their baseline 

assessments and reassessments on their gas transmission pipelines (as 

measured in miles) during the off-peak spring and summer months, 18 

percent in the fall, and 6 percent in the winter. According to an INGAA 

official, most of the assessment activity that results in temporary 

reductions in gas supply due to repairs being made will likely affect 

markets regionally. If assessments occur when pipelines are constrained 

for capacity, an increase in delivered gas prices will occur. Overall, 

assessments will only affect small groups of the nation’s population, but 

they will have a consumer price impact in those affected areas. 

Our findings from these operators, while not necessarily representative of 

all operators, are encouraging. First, these findings do represent a sizeable 

proportion (61 percent) of the mileage assessed to date. Second, the 

segments that operators assessed were supposed to be the riskiest 

segments (those most susceptible to ruptures or leaks) of the gas 

transmission pipelines located in highly populated or frequently used areas. 

If so, there should be fewer repairs needed for subsequent baseline 

assessments of less risky segments, and hence fewer disruptions in supply. 

13According to a Department of Energy official, on- and off-peak periods vary based on 

location. For example, in the South, fall and winter months are often off-peak while the 

reverse is true in northern states (e.g., for heating needs). 
Appendix I

Impact of Periodic Reassessments on Natural 

Gas Supply May Be Less than Foreseen

Page 35 GAO-06-945 Pipeline Reassessment Requirements

Post-act Industry Polling 

Found Members Plan to 

Modify and Repair 

Pipelines, Which May Affect 

Natural Gas Supply

The 2006 INGAA and AGA polling of their members did not explicitly ask 

for the extent to which their members experienced supply disruptions 

because of baseline assessments or repairs. However, INGAA and AGA did 

ask members to identify the amount of pipeline modifications and repairs 

that would be necessary for conducting baseline assessments and 

reassessments, activities that could disrupt supply. Overall, INGAA and 

AGA found that about 50,000 of the 180,000 miles of gas transmission 

pipelines that were reported by responding operators are scheduled for or 

have already undergone (1) modifications to allow in-line inspection tools 

to access pipeline segments (2) repairs to eliminate major defects or (3) 

monitoring for minor problems.14 According to a senior INGAA official, 

assessments and pipeline modifications can generally follow a prearranged 

schedule; however, pipeline repairs are unpredictable. Repairs often 

require pipelines to be shut down, which could have an effect on natural 

gas supply.15 However, PHMSA officials report that only the worst pipeline 

problems require pipelines to be shutdown for repair. From 2003 to 2012, 

38,000 of the 50,000 pipeline miles (76 percent) have been scheduled for

14In its September 2003 report, cited earlier, the National Petroleum Council estimated that 

conducting baseline assessments over 10 years, gas transmission pipeline operators will 

spend about $1.1 billion annually on replacing existing pipeline infrastructure. 

15In March 2006, PHMSA issued a final rule that requires operators to use a risk-based 

approach to determine which onshore gathering pipelines are subject to PHMSA’s gas 

pipeline safety rules and which of these rules the lines must meet. The application of these 

rules may result in interruption of service to carry out repairs. However, the rules do not 

impose requirements for operators to assess their pipelines in the same manner as the 

integrity management program. Therefore, any interruptions caused by the need to carry out 

repairs would be the result of normal operation and maintenance activities. Gathering lines 

collect natural gas from production facilities and transport them to transmission or 

distribution lines. There are about 15,000 miles of onshore gathering lines nationwide. 
Appendix I

Impact of Periodic Reassessments on Natural 

Gas Supply May Be Less than Foreseen

Page 36 GAO-06-945 Pipeline Reassessment Requirements

modifications or repairs during the off-peak spring and summer months to 

mitigate supply disruptions.16 

Department of Energy 

Expects Little Disruption in 

the Natural Gas Supply

Officials from the Office of Oil and Gas within the Department of Energy 

told us that the integrity management program, including the 7-year 

reassessment requirement, is not likely to significantly disrupt the natural 

gas supply. They told us that operators have, among other things, sufficient 

system redundancies, such as parallel lines, to maintain product supply. 

The Department of Energy has completed several regional analyses of the 

possible effects of the disruptions in the natural gas supply caused by such 

events as extreme weather conditions (e.g., extended cold periods and 

hurricanes). It is completing other analyses as well. However, because 

these are being done at the regional level, their results are too broad to help 

inform us about more localized and subregional potential disruptions. 

16Complying with environmental laws, such as those dealing with habitats, may also affect 

scheduling of modifications and repairs. The Pipeline Safety Improvement Act of 2002 

required the establishment of a federal interagency committee to develop and ensure 

implementation of a coordinated environmental review and permitting process to enable 

operators to complete baseline assessments, including pipeline repairs, with minimal 

adverse effects to the environment such as harming unique species or habitat in the 

specified time periods. The interagency committee has established a working group to 

develop a joint regulatory approach to streamlining. In addition, PHMSA has designed and is 

testing a Web-based environmental permit review process to (1) provide early electronic 

notification of proposed pipeline repairs to federal agencies and solicit input from state and 

local agencies involved in the review process for pipeline repairs and (2) expedite 

coordination and approval of recommended best practices for operators to use to manage 

environmental damage when repairing their pipelines in environmentally important areas.
Page 37 GAO-06-945 Pipeline Reassessment Requirements

Appendix II

Scope and Methodology ApendxiI

To understand how the findings from operators’ baseline assessments 

inform us about the need to reassess gas transmission pipelines at least 

every 7 years, we reviewed the requirements of the Pipeline Safety 

Improvement Act of 2002 and PHMSA’s implementing regulations. We also 

reviewed information about setting reassessment intervals for gas 

transmission pipelines, including industry consensus standards for 

maximum reassessment intervals developed by the American Society of 

Mechanical Engineers, and documents obtained from PHMSA, industry, 

and other stakeholders. We discussed this issue with officials from PHMSA, 

other federal agencies, industry associations, companies that perform 

research in this area, state safety representatives, and safety advocacy 

groups. (These organizations are listed at the end of this appendix.)

We also analyzed data from PHMSA on the number of immediate repairs 

reported by operators as a result of baseline assessments conducted 

through December 2005 (latest data available) and the number of natural 

gas pipeline incidents reported to PHMSA.

We contacted 52 pipeline operators (50 natural gas and 2 hydrogen 

operators) from among the 447 operators that reported that they operate 

gas transmission pipelines in highly populated or frequently used areas. 

Forty-four of these operators have begun baseline assessments. We 

selected those operators for which the baseline assessments and 

reassessments could be expected to have the greatest impact, all else being 

equal: larger and smaller transmission pipelines and local distribution 

companies with the highest proportion of pipeline miles in highly 

populated or frequently used areas to total system miles. We also selected 

operators located in three regions of the country that several studies and 

our stakeholders consider to be vulnerable to energy supply disruptions: 

the Northeast, the Southwest, and the Rocky Mountains. 

The 52 operators reported that they have assessed about 4,100 of the 6,700 

miles (61 percent) of pipeline segments, as of December 2005. Overall, 

these operators have assessed about 21 percent of the 20,000 miles of 

pipeline that operators have reported as being within highly populated or 

frequently used areas. Because we used a nonprobability method of
Appendix II

Scope and Methodology

Page 38 GAO-06-945 Pipeline Reassessment Requirements

selecting these operators, we cannot project our findings nationwide.1 

Contacting a larger number of operators or selecting them through a 

statistical sample would not have been feasible due to resource and time 

constraints. Nonetheless, these 52 operators do represent a substantial 

portion of the miles assessed to date and of the total number of reported 

miles of pipeline in highly populated or frequently used areas. 

For these 52 operators, we conducted semistructured interviews to collect 

qualitative and quantitative information on the degree to which they found 

anomalies during the baseline assessments and, based on these results, the 

frequency with which they would reassess these pipeline segments under 

American Society for Mechanical Engineers standards for managing the 

system integrity of gas pipelines (ASME B31.8S-2004) if the 7-year 

reassessment requirement were not in place. As part of our work, we asked 

operators to identify the steps that they take to ensure the quality of their 

baseline assessments and reassessments, such as ensuring that competent 

persons are involved in determining reassessment intervals and conducting 

periodic internal or third-party reviews of their integrity management 

programs, as recommended by PHMSA regulations and industry standards. 

We relied on the operators’ professional judgment in reporting on the 

conditions they found during their assessments. 

To determine the extent to which gas transmission pipeline operators and 

local distribution companies will likely have the resources to reassess their 

pipelines, at least every 7 years, we synthesized testimonial and 

documentary evidence obtained from our discussions with (1) 52 operators 

(as described above) and (2) pipeline assessment tool contractors, direct 

assessment vendors, and industry associations on the prospective 

availability of equipment, equipment operators, and data analysts to 

interpret results. We synthesized the information from the 52 operators to 

determine the aggregate level of actual and planned assessments and 

reassessments through 2012. We compared our findings with the results 

from an INGAA/AGA data collection effort, conducted in 2006, on the same 

topic. We then discussed our results with INGAA and analyzed the data 

obtained from both efforts to try to understand any differences in results.

1

Results from nonprobability samples cannot be used to make inferences about a population 

because, in a nonprobability sample, some elements of the population being studied have no 

chance or have an unknown chance of being selected as part of the sample. 
Appendix II

Scope and Methodology

Page 39 GAO-06-945 Pipeline Reassessment Requirements

To assess the reliability of information provided to us from PHMSA, 

INGAA, and AGA, we performed a number of analyses. For the information 

provided to us from PHMSA, we compared the number of immediate 

repairs operators reported to us to the number of immediate repairs they 

reported to PHMSA. To assess the reliability of the data provided to us from 

INGAA and AGA, we also compared the reported responses of operators 

that were included in INGAA/AGA’s and our efforts. In addition, we 

checked the accuracy of INGAA/AGA’s calculations. We determined that 

the data were sufficiently reliable for the types of analyses we present in 

this report.

Other Aspects of Our 

Work

To determine the potential impact of the 7-year reassessment requirement 

on the nation’s natural gas supply, we contacted officials from PHMSA, the 

Department of Energy, industry associations, and research firms to discuss 

how the potential shutdown of gas transmission pipelines or operation 

under reduced pressure—as a result of baseline assessments, 

reassessments, and repairs—might affect the continued supply of natural 

gas. We also obtained information from the Department of Energy on the 

results of analyses of the overall vulnerability of natural gas supplies in 

several regions of the nation to extreme conditions, such as extreme cold 

weather. 

Further, we asked the 50 natural gas operators that we contacted about the 

vulnerability of their pipelines to supply disruption and the potential 

impact on customers. This included 11 operators located in the three 

regions of the country that have limited excess supply gas capacity. We also 

discussed how their baseline assessments and any resulting repairs have 

affected their customers to date. Finally, we compared operators’ 

experiences in performing assessments, reassessments, and repairs to the 

assumptions made in the 2002 INGAA study of the potential effects of the 

proposed integrity management program, two reviews of this study, and 

PHMSA’s final regulatory evaluation. The reviews were performed by the 

John A. Volpe National Transportation Systems Center and the Department 

of Energy at the request of PHMSA.2

2

As cited in appendix I.
Appendix II

Scope and Methodology

Page 40 GAO-06-945 Pipeline Reassessment Requirements

Organizations 

Contacted

In addition to the 52 pipeline operators and four inspection contractors that 

we contacted, we met with or contacted the following organizations:

Department of Transportation

Office of Inspector General

Pipeline and Hazardous Materials Safety Administration

Other Federal Agencies

Department of Energy

Federal Energy Regulatory Commission

National Institute of Standards and Technology

National Transportation Safety Board

Industry Associations

American Gas Association

American Public Gas Association

Inline Inspection Association

Interstate Natural Gas Association of America

Midwest Energy Association

Northeast Gas Association

State Regulatory Associations

National Association of Pipeline Safety Representatives

National Association of Regulatory Utility Commissioners

New Jersey Public Utility Commission

Research Firms

Energy and Environmental Analysis, Inc.

Battelle

Gas Technology Institute

John A. Volpe National Transportation Systems Center

Pipeline Research Council International
Appendix II

Scope and Methodology

Page 41 GAO-06-945 Pipeline Reassessment Requirements

Technical Experts

American Society of Mechanical Engineers

American Society for Testing and Materials

Kiefner and Associates, Inc.

National Association of Corrosion Engineers

Pipeline Safety Advocacy Groups

Common Ground Alliance

Cook Inlet Keeper

Pipeline Safety Trust
Page 42 GAO-06-945 Pipeline Reassessment Requirements

Appendix III

Contact and Staff Acknowledgments ApendxiI

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

Staff 

Acknowledgments

In addition to the above, James Ratzenberger, Assistant Director; Timothy 

Bober; Anne Dilger; Seth Dykes; Timothy Guinane; Brandon Haller; Bert 

Japikse; and Matthew LaTour made key contributions to this report.

(542069)
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