GAS PIPELINE 

SAFETY

Guidance and More 

Information Needed 

before Using RiskBased Reassessment 

Intervals

Report to Congressional Committees

June 2013

GAO-13-577

United States Government Accountability Office
United States Government Accountability Office

Highlights of GAO-13-577, a report to 

congressional committees

June 2013

GAS PIPELINE SAFETY

Guidance and More Information Needed before 

Using Risk-Based Reassessment Intervals

Why GAO Did This Study

About 300,000 miles of gas 

transmission pipelines cross the United 

States, carrying natural gas from 

processing facilities to communities 

and large-volume users. These 

pipelines are largely regulated by 

PHMSA. The Pipeline Safety 

Improvement Act of 2002 established

the gas integrity management 

program, which required gas 

transmission pipeline operators to 

assess the integrity of their pipeline

segments in high consequence areas 

by December 2012 and reassess them 

at least every 7 years.

The Pipeline Safety, Regulatory 

Certainty, and Job Creation Act of 

2011 directed GAO to examine the 

results of these baseline assessments 

and reassessments and the potential

impact of making the current process 

more risk-based. GAO analyzed (1)

PHMSA’s assessment data on repairs 

made and the appropriateness of the 

7-year reassessment requirement, (2) 

the impact of the 7-year reassessment 

requirement on regulators and 

operators, and (3) the potential 

challenges of implementing risk-based 

reassessment intervals beyond 7 

years. GAO analyzed assessment 

data; reviewed legislation and 

regulations; and interviewed pipeline 

operators, federal and state regulators, 

and other stakeholders.

What GAO Recommends

DOT should (1) develop guidance for 

operators to calculate reassessment 

intervals and (2) collect information on 

the resources needed to implement 

risk-based reassessment intervals 

beyond 7 years. DOT did not agree or 

disagree with the recommendations, 

but provided technical comments. 

What GAO Found

Baseline assessment and reassessment data collected by the Department of 

Transportation’s (DOT) Pipeline and Hazardous Materials Safety Administration 

(PHMSA) since 2004 show that pipeline operators are making repairs in highly 

populated or frequented areas (“high consequence areas”). For example, from 

2004 to 2009, operators made 1,080 immediate repairs. While operators can use 

assessment data to determine reassessment intervals for specific pipelines, 

PHMSA’s data are aggregated and cannot indicate an appropriate maximum 

interval for all pipelines nationwide. Such a determination requires, for example, 

collaboration of subject matter experts and analysis of technical studies. 

The current 7-year reassessment requirement provides a safeguard by allowing 

regulators and operators to identify and address problems on a continual basis, 

but is not fully consistent with risk-based practices. The 7-year reassessment 

requirement is more frequent than the intervals found in industry consensus 

standards and provides greater assurance that operators are regularly monitoring 

their pipelines to address threats before leaks or ruptures occur. However, this 

requirement—which was established in a 2002 act as part of the gas integrity 

management program rather than by rulemaking—is not fully consistent with riskbased management practices, which ask operators to, for example, use 

information to identify, assess, and prioritize risks so that resources may be 

allocated to address higher risks first. While operators are required to determine 

an appropriate reassessment interval based on the threats to their pipelines in 

high consequence areas, they must reassess those pipelines at least every 7 

years regardless of the risks identified. 

Implementing risk-based reassessment intervals beyond 7 years would require a 

statutory change from Congress and could exacerbate current workload, staffing, 

and expertise challenges for regulators and operators. For example, PHMSA is 

facing workload problems with inspections, which could be worsened by allowing 

operators to use risk-based reassessment intervals beyond 7 years; PHMSA has 

an initiative under way that could help address this issue. Further, some 

operators told us that extending reassessment intervals beyond 7 years would 

likely require additional data analyses over what is currently required. Operators 

GAO met with varied in the extent to which they currently calculate reassessment 

intervals and use the results of data analyses. Guidance to calculate 

reassessment intervals is lacking, and as a result, operators may perform a less 

rigorous determination of their reassessment intervals at this time. At Congress’s 

request, in 2008 PHMSA described how it would establish and enforce riskbased criteria for extending the 7-year reassessment interval. PHMSA proposed 

retaining the current 7-year reassessment requirement, but establishing a 

process by which operators could use risk-based reassessment intervals beyond 

7 years if they met certain potential criteria, such as demonstrating sound risk 

analysis. While PHMSA and GAO have supported the concept of risk-based 

reassessment intervals beyond 7 years, given the breadth of potential challenges 

with implementation, more information might help decision-makers better 

understand the resource requirements for this change. For example, PHMSA has 

used pilot programs to collect such information and study the effects prior to rule 

changes.

View GAO-13-577. For more information, 

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

or flemings@gao.gov. 
Page i GAO-13-577 Gas Pipeline Reassessment Intervals

Letter 1 

Background 3

Data Show Critical Pipeline Repairs Are Being Made, but Cannot 

Be Used to Determine an Appropriate Maximum Reassessment 

Interval for All Pipelines Nationwide 13

The 7-Year Reassessment Requirement Provides a Safeguard, but Is 

Not Fully Consistent with Risk-Based Practices 20

Implementing Risk-Based Reassessment Intervals beyond 7 Years 

Could Exacerbate Current Challenges and Would Benefit from 

More Information on Resource Requirements 24

Conclusions 31

Recommendations for Executive Action 32

Agency Comments 32

Appendix I Objectives, Scope, and Methodology 34

Organizations Contacted 36

Appendix II Potential Criteria for Risk-Based Reassessment Intervals 39

Appendix III GAO Contact and Staff Acknowledgments 41

Table

Table 1: Examples of Potential Criteria for Risk-Based Pipeline 

Reassessment Intervals 29

Figures

Figure 1: Gas Transmission Pipeline Mileage in High Consequence 

Areas Assessed by Pipeline Operators from 2004 to 2011 6

Figure 2: In-Line Inspection Device Being Placed in a Launcher 8

Figure 3: Some Examples in Which a Gas Transmission Pipeline 

Operator Can Meet Reassessment Requirements 11

Figure 4: Repairs Made by Pipeline Operators in High Consequence 

Areas Resulting from Assessments from 2004 to 2009 15

Contents 
Page ii GAO-13-577 Gas Pipeline Reassessment Intervals

Abbreviations

2002 act Pipeline Safety Improvement Act of 2002

ASME American Society of Mechanical Engineers

PHMSA Pipeline and Hazardous Materials Safety Administration

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Page 1 GAO-13-577 Gas Pipeline Reassessment Intervals

441 G St. N.W.

Washington, DC 20548

June 27, 2013

The Honorable John D. Rockefeller IV

Chairman

The Honorable John Thune

Ranking Member

Committee on Commerce, Science, and Transportation

United States Senate

The Honorable Fred Upton

Chairman

The Honorable Henry Waxman

Ranking Member

Committee on Energy and Commerce

House of Representatives

The Honorable Bill Shuster

Chairman

The Honorable Nick J. Rahall, II

Ranking Member

Committee on Transportation and Infrastructure

House of Representatives

About 300,000 miles of transmission pipelines across the United States 

carry natural gas from processing facilities to communities and largevolume users, such as power plants and factories. These pipelines, which 

are largely regulated by the Department of Transportation’s Pipeline and 

Hazardous Materials Safety Administration (PHMSA), are relatively safe 

when compared with other modes of transporting hazardous goods (e.g., 

highway and rail). However, when pipelines leak or rupture, the results 

can be devastating, including fatalities, injuries, and extensive property or 

environmental damage. Such an incident occurred in September 2010 in 

San Bruno, California, killing eight people and damaging or destroying 

over 100 homes.

The Pipeline Safety Improvement Act of 2002 (2002 act) required PHMSA 

to implement a risk-based approach to gas transmission pipeline safety, 

an approach known as “integrity management.” The integrity 

management program requires operators to, among other things, 

systematically identify threats and mitigate risks to pipeline segments 

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

frequented areas. Specifically, the 2002 act required operators of gas 

 
 

Page 2 GAO-13-577 Gas Pipeline Reassessment Intervals

transmission pipelines to complete a baseline assessment looking for 

safety threats to their pipelines in high consequence areas by December 

2012, and complete reassessments of those pipelines at least every 7 

years,

1

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

mandated that GAO examine the results of baseline assessment and 

reassessment data for gas transmission pipelines, as well as the impact 

to stakeholders of making assessments more risk-based.

a time frame that some stakeholders feel is too frequent. PHMSA 

and state pipeline safety offices conduct inspections and other efforts to 

oversee operators’ compliance with this program.

2

To address the extent to which PHMSA’s assessment data provides 

information on repairs and the appropriateness of the 7-year 

reassessment requirement, we analyzed PHMSA data from 2004 to 2011 

on gas transmission pipelines, including: age and operating pressure of 

transmission pipelines, pipeline miles assessed, tools used to conduct 

assessments, and conditions found during assessments and 

subsequently repaired. We assessed the reliability of the PHMSA data by 

speaking with agency officials about data quality control procedures and 

reviewing relevant documentation. We determined that the data were 

sufficiently reliable to provide background information and to describe 

repairs made in high consequence areas. To determine the impact of the

7-year reassessment requirement as well as the potential challenges to 

regulators and operators of using risk-based reassessment intervals 

beyond 7 years, we reviewed relevant legislation, PHMSA regulations, 

and PHMSA documents. We also interviewed selected federal and state 

regulators, industry associations, gas transmission pipeline operators, 

pipeline safety advocacy and environmental groups, research firms, a 

state regulatory association, and technical experts. We spoke with a nonThis report 

contains information on: (1) the extent to which PHMSA’s assessment 

data provides information on repairs made and the appropriateness of the 

7-year reassessment requirement, (2) the impact of the 7-year 

reassessment requirement on regulators and operators, and (3) the 

potential challenges of implementing risk-based reassessment intervals 

beyond 7 years.

 

1

Pub. L. No. 107-355, § 14(a), 116. Stat. 2985, 3002 (2002) (codified as amended at 49 

U.S.C. § 60109(c)(3)(A)-(B)). 

2

Pub. L. No. 112-90, § 5(g), 125 Stat. 1904, 1909 (2012).
 

Page 3 GAO-13-577 Gas Pipeline Reassessment Intervals

generalizable sample of 27 gas transmission pipeline operators that we 

selected using several criteria, including the number of pipeline miles in 

high consequence areas, recent incidents caused by corrosion, and 

geographic location. We also spoke with a non-generalizable sample of 8 

state pipeline safety offices that were selected based on several factors, 

including total pipeline mileage within the state and geographic location. 

We collected additional information from three pipeline operators on their 

experience calculating reassessment intervals and conducting 

reassessments. For more information on our scope and methodology, 

see appendix I.

We conducted this performance audit from July 2012 to June 2013 in 

accordance with generally accepted government auditing standards. 

Those standards require that we plan and perform the audit to obtain 

sufficient, appropriate evidence to provide a reasonable basis for our 

findings and conclusions based on our audit objectives. We believe that 

the evidence obtained provides a reasonable basis for our findings and 

conclusions based on our audit objectives.

The United States has a network of about 300,000 miles of gas 

transmission pipelines that are owned and operated by approximately 900 

operators. These pipelines, which are primarily interstate, typically move 

gas products over long distances from sources to communities, and tend 

to operate at the highest pressures and have the largest diameters of any 

type of pipeline.3

PHMSA administers the national regulatory program to ensure the safe 

transportation of natural gas and hazardous liquids (e.g., petroleum or 

Gas transmission pipelines are critical because they 

transport nearly all of the natural gas used in the United States, which 

fuels about a quarter of the nation’s energy needs. Pipelines do not 

experience many of the safety threats faced by other forms of freight 

transportation because they are mostly underground. However, they are 

subject to problems that can occur over time (such as leaks and ruptures 

resulting from corrosion) or are independent of time (such as damage 

from excavation, land movement, or incorrect operation). 

 

3

Gathering pipelines collect gas from production areas and transport it to processing 

facilities, which in turn refine and send the products to transmission pipelines. Local 

distribution pipelines, which are primarily intrastate, receive gas from transmission 

pipelines and distribute it to commercial and residential end users.

Background 
 

Page 4 GAO-13-577 Gas Pipeline Reassessment Intervals

anhydrous ammonia) by pipeline, including developing safety 

requirements that all pipeline operators regulated by PHMSA must meet.4

Pipeline operators are subject to PHMSA’s minimum safety standards for 

the design, construction, testing, inspection, operation, and maintenance 

of gas transmission pipelines. However, this approach does not 

systematically account for differences in the kinds of threats and the 

degrees of risk that individual 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. Federal efforts to incorporate risk-based concepts 

into pipeline management began in earnest in the mid-1990s. For 

example, the Accountable Pipeline Safety and Partnership Act of 1996 

required the Department of Transportation to establish risk management 

demonstration projects.

In fiscal year 2012, the agency’s total budget was $201 million, about half 

of which is for pipeline safety activities. PHMSA’s Office of Pipeline Safety 

employs over 200 staff, with about 135 of those staff involved in 

inspections and enforcement. In addition, over 300 state inspectors help 

oversee pipelines and ensure safety.

5 The purpose of this effort was “to demonstrate, 

through the voluntary participation by owners and operators of gas 

pipeline facilities and hazardous liquid facilities, the application of risk 

management; and to evaluate the safety and cost-effectiveness of the 

program.”6

 

4

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

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

population centers, operate at low pressures, or primarily involve intrastate pipelines.

These projects helped PHMSA establish a more risk-based 

approach to safety: the integrity management program. Integrity 

management helps ensure safety by, among other things, using 

information to identify and assess risks and prioritizing risks so that 

resources may be allocated to address higher risks first. The integrity 

management program requires operators to perform a number of 

activities, such as identifying high consequence areas and pipelines 

5

Pub. L. No. 104-304, § 5, 110 Stat. 3798 (1996).

6

49 U.S.C. § 60126(a)(1)(A), (B).
 

Page 5 GAO-13-577 Gas Pipeline Reassessment Intervals

within those areas,7 as well as identifying the threats facing those 

pipelines. PHMSA first implemented integrity management requirements 

for hazardous liquid pipeline operators with 500 or more miles of pipelines 

in December 2000, followed by hazardous liquid pipeline operators with 

less than 500 miles in January 2002. The Pipeline Safety Improvement 

Act of 2002 extended the integrity management program to gas 

transmission pipelines, which include about 20,000 miles of pipeline 

segments located in high consequence areas.8

As part of the integrity management program, operators are required to 

assess the integrity of their pipelines within high consequence areas on a

regular basis using approved methods. Specifically, gas transmission 

pipeline operators were required to complete a baseline assessment on 

pipeline segments within high consequence areas by December 17, 

2012. According to the 2002 act, operators are then required to complete 

reassessments of these pipelines at least every 7 years. Gas 

transmission pipeline operators completed most baseline assessments by 

December 17, 2012, and reassessments are currently under way.

In addition to being 

subject to PHMSA’s integrity management program, operators must still 

meet the minimum safety standards noted above.

9 From 

2004 through December 2011 (the latest data available), baseline 

assessments were conducted on over 23,450 miles of gas transmission 

pipeline in high consequence areas.10

 

7

Examples of high consequence areas for gas transmission pipelines could include: (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); or (3) a facility occupied by persons who would be difficult to evacuate, such as a 

hospital or school. 49 C.F.R. § 192.903.

Over 4,470 miles of gas 

8

Prior to enactment of the Pipeline Safety Improvement Act of 2002, PHMSA was 

exploring a rulemaking for integrity management for gas transmission pipelines.

9

When a pipeline operator identifies a new high consequence area, the operator must 

complete the baseline assessment of the affected pipeline segment within 10 years from 

the date the high consequence area is identified. See 49 C.F.R. §192.921(f).

10The total gas transmission pipeline mileage within high consequence areas changes 

from year to year due to, for example, changes in the population near the pipeline, or as 

pipeline segments are placed in to or taken out of service. According to PHMSA’s data, 

the total mileage from 2004 to 2011 has ranged from a low of 19,139 miles to a high of 

21,765 miles. Given the annual change in pipeline miles in high consequence areas, the 

miles of completed baseline assessments and reassessments exceeds the current 

number of pipeline miles in high consequence areas.
 

Page 6 GAO-13-577 Gas Pipeline Reassessment Intervals

transmission pipeline in high consequence areas—or about 20 percent of 

the pipeline miles that had a completed baseline assessment between 

2004 and 2011—were reported as reassessed between 2008 and 2011 

(see fig. 1).11

Figure 1: Gas Transmission Pipeline Mileage in High Consequence Areas Assessed 

by Pipeline Operators from 2004 to 2011

Among other things, PHMSA’s integrity management 

regulations required operators to (1) prioritize their baseline assessments 

to assess riskier pipelines first and (2) complete baseline assessments of 

these riskier pipelines by December 2007, and all pipelines within high 

consequence areas by December 2012. As a result, a small spike in the 

mileage assessed occurred in 2007.

Note: According to PHMSA, data on assessments of gas transmission pipelines in high consequence 

areas between 2004 and 2009 may include over-reporting of the total miles assessed. In some cases, 

 

11PHMSA began collecting data on reassessments in 2008. Prior to 2008, pipeline 

operators could only report to PHMSA the number of miles on which they had conducted 

baseline assessments.
 

Page 7 GAO-13-577 Gas Pipeline Reassessment Intervals

pipeline operators that used two different types of assessment tools may have reported to PHMSA 

the mileage assessed by these tools twice.

Under PHMSA’s regulations, gas transmission pipeline operators may 

use any of three primary approaches to conduct assessments:

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

tool—often known as a smart pig—through the pipeline to detect and 

record anomalies, such as metal loss and damage (see fig. 2). 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. In-line inspection devices can be 

run only from specific launch and retrieval points, which may extend 

beyond high consequence areas. Operators using in-line inspection 

will often gather information along the entire distance between 

launching and retrieval locations to gain additional safety information. 

Based on PHMSA’s data, the majority of pipeline miles assessed in 

2011 (88 percent) were done using in-line inspection.
 

Page 8 GAO-13-577 Gas Pipeline Reassessment Intervals

Figure 2: In-Line Inspection Device Being Placed in a Launcher

• Direct assessment: Direct assessment is an aboveground 

assessment method used to identify problem areas on a pipeline. The 

process includes gathering data on potential risks facing the pipeline, 

analyzing those data to identify potential problem locations, and then 

excavating and directly examining those locations. PHMSA 

regulations require that at least two or more aboveground detection 

instruments, such as a close interval survey,12

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

the pipeline, removing the gas product and replacing 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 

be used to constitute a 

direct assessment.

 

12During a close interval survey, measurements of the soil along a pipeline’s right-of-way 

are taken at regular distances (i.e., about every 3 feet) to determine if there is any 

corrosion damage to the pipeline.
 

Page 9 GAO-13-577 Gas Pipeline Reassessment Intervals

pipeline is excavated to determine the cause of the failure. Operators 

must shut down pipelines to perform hydrostatic testing. Also, this 

assessment method can weaken the pipeline due to the high 

pressures involved, making it more susceptible to failure later. Finally, 

operators must be able to dispose of large quantities of waste water in 

an environmentally responsible manner.

According to the operators we spoke with, the costs associated with 

performing each of these assessment methods varies greatly. For 

example, operators told us that the estimated average cost for conducting 

a direct assessment ranges from $5,000 per mile to $500,000 per mile. 

The costs vary due to a number of factors, such as the amount of pipeline 

mileage to be assessed and the number of digs that must be performed 

after completing an assessment to confirm the findings.

PHMSA’s regulations promulgated pursuant to the Pipeline Safety 

Improvement Act of 2002 require gas transmission pipeline operators to 

reassess their pipelines for all safety risks—such as corrosion, 

excavation, land movement, or incorrect operation—at regular intervals 

based on industry consensus standards. But the regulations limit the 7-

year reassessment requirement in the 2002 act to corrosion damage only

because corrosion is the most frequent cause of failures that can occur 

over time. The industry consensus standards adopted in PHMSA’s 

regulations require that gas transmission pipeline operators reassess 

their pipelines for all safety risks at least every 10, 15, or 20 years,13

depending primarily on the condition and operating pressure of the 

pipelines, with pressure measured as a percentage of specified minimum 

yield strength.14

 

1349 C.F.R. § 192.939. 

If an operator elects to establish a reassessment interval 

for all safety risks based on the industry consensus standards, it must—in 

order to comply with the 2002 act—perform what is called a “confirmatory 

direct assessment” by at least the seventh year to assess corrosion 

14Pipelines will begin to deform at a certain level of operating pressure. As a result, 

pipelines operate at a percentage of the level of pressure that will cause the pipeline to 

deform, known as “specified minimum yield strength.” The specified minimum yield 

strength depends on the type of metal and is an indicator of when the metal in the pipe 

starts to yield, deforming in a way that does not return to its original shape. By definition, 

transmission pipelines operate at or above 20 percent of specified minimum yield strength. 

49 C.F.R. § 192.3.
 

Page 10 GAO-13-577 Gas Pipeline Reassessment Intervals

damage,15

 

15Confirmatory direct assessment is similar to direct assessment; however, operators are 

required to use only one type of assessment tool, rather than at least two types as 

required for direct assessment.

and then conduct the reassessment for all safety risks at the 

interval the operator established. Alternatively, an operator can elect to 

perform a reassessment for all safety risks (including corrosion damage) 

at least every 7 years in order to comply with both the 2002 act and 

PHMSA’s regulations. Figure 3 provides some examples in which an 

operator can meet its reassessment requirements, either through 

performing (1) a confirmatory direct assessment at year 7 and a 

reassessment for all safety risks at a later year that comports with the 

industry consensus standards, or (2) a reassessment for all safety risks 

every 7 years.
 

Page 11 GAO-13-577 Gas Pipeline Reassessment Intervals

Figure 3: Some Examples in Which a Gas Transmission Pipeline Operator Can Meet Reassessment Requirements

a

Gas transmission pipeline operators with pipeline segments operating below 30 percent specified 

minimum yield strength and who elect to use a 20-year reassessment interval can choose to perform 

either a confirmatory direct assessment or a “low stress reassessment” by years 7 and 14. A low 

stress reassessment involves the operator performing various tests or surveys to identify potential 

changes in external or internal corrosion. See 49 C.F.R. § 192.941.
 

Page 12 GAO-13-577 Gas Pipeline Reassessment Intervals

The 7-year reassessment requirement in the Pipeline Safety 

Improvement Act of 2002 as well as the reassessment intervals noted in 

PHMSA’s regulations and the industry consensus standards are 

maximum reassessment intervals: they represent the maximum number 

of years between reassessments. If pipeline conditions and risks dictate 

more frequent reassessments, then pipeline operators must do so to 

comply with PHMSA’s regulations.16 In addition, between reassessments, 

operators must—regardless of whether their pipeline mileage is located in 

a high consequence area—patrol their pipelines, survey for leakage, 

maintain valves, ensure that corrosion-preventing cathodic protection is 

working properly,17

In general, PHMSA has full responsibility for inspecting interstate 

pipelines and enforcing regulations pertaining to them,

and take measures to prevent excavation damage.

18 although some 

states are designated as “interstate agents” to assist PHMSA.19 PHMSA 

also has arrangements with the 48 contiguous states, the District of 

Columbia, and Puerto Rico to assist with overseeing intrastate pipelines. 

State pipeline safety offices are allowed to issue regulations 

supplementing or extending federal regulations for intrastate pipelines, 

but these state regulations must be at least as stringent as the minimum 

federal regulations.

 

16Pipeline 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.

17Cathodic protection involves a small electrical voltage between a structure and the 

ground to control corrosion.

1849 U.S.C. § 60102.

1949 U.S.C. § 60106.
 

Page 13 GAO-13-577 Gas Pipeline Reassessment Intervals

PHMSA’s baseline assessment and reassessment data from 2004 to 

2011 show that pipeline operators have identified and are making critical 

repairs in high consequence areas, specifically for conditions requiring 

repairs immediately or within one year.20 For immediate conditions, 

operators must make a repair as soon as possible and reduce pipeline 

operating pressure or shut down the pipeline until the repair is completed. 

A dent in a pipeline wall that also appears to have cracks would be 

considered a condition in need of immediate repair. For scheduled 

conditions,21

 

20PHMSA regulations require that pipeline operators take prompt action to address all 

anomalous conditions the operator discovers through baseline assessments and 

reassessments. 49 C.F.R. § 192.933(a).

operators must make repairs within one year or observe the 

condition during subsequent assessments for any changes that would 

require repair. A dent with a depth of more than two percent of the 

21For our review, we refer to one-year and monitored conditions as “scheduled” 

conditions. See 49 C.F.R. §§192.933(c), (d)(1), (d)(2), and (d)(3). PHMSA’s data 

collection of scheduled repairs made from 2004 to 2009 did not differentiate between oneyear and monitored conditions. According to PHMSA, this may have resulted in some 

pipeline operators reporting data on scheduled repairs differently. For example, some 

pipeline operators may have reported a scheduled repair as any non-immediate repair 

made; some may have reported only repairs of monitored conditions, not one-year repair 

conditions. PHMSA’s 2010 and 2011 annual reports help address this by having pipeline 

operators report separately on the number of immediate repair conditions, one-year 

conditions, monitored conditions, and other “scheduled” conditions repaired.

Data Show Critical 

Pipeline Repairs Are 

Being Made, but 

Cannot Be Used to 

Determine an 

Appropriate 

Maximum 

Reassessment Interval 

for All Pipelines 

Nationwide 

Assessments Have 

Resulted in Critical 

Pipeline Repairs
 

Page 14 GAO-13-577 Gas Pipeline Reassessment Intervals

pipeline’s diameter located near certain sections of the pipeline wall 

would be considered a scheduled condition that must be repaired within 

one year. Pipeline operators report annually to PHMSA the number of 

immediate and scheduled repairs made on their pipelines that were 

identified through assessments. Miles assessed and repairs are reported 

in the year they are conducted. PHMSA data show that from 2004 to 

2009, pipeline operators reported making 1,080 immediate repairs and 

2,261 scheduled repairs (see fig. 4). The data also show that during 2010 

and 2011, pipeline operators reported 387 immediate conditions repaired 

and 2,246 scheduled conditions repaired. A PHMSA official told us that a 

2010 change in reporting requirements resulted in the increase in 

reported conditions repaired beginning in 2010.22

 

22In 2010, PHMSA changed how pipeline operators were required to report repair data. 

From 2004 to 2009, pipeline operators reported the number of repairs completed for 

immediate and scheduled conditions with one repair potentially fixing multiple conditions. 

For data collected in 2010 and later, pipeline operators were required to report the number 

of individual conditions repaired. As compared to 144 immediate repairs in 2009,132 

immediate conditions were repaired in 2010 and 255 in 2011. The number of scheduled 

conditions repaired was 1,027 in 2010 and 1,219 in 2011; there were 266 scheduled 

repairs in 2009. 
 

Page 15 GAO-13-577 Gas Pipeline Reassessment Intervals

Figure 4: Repairs Made by Pipeline Operators in High Consequence Areas 

Resulting from Assessments from 2004 to 2009

Note: According to PHMSA, repairs reported in one year may not have been identified by 

assessments performed in that same year. There is a potential lag between when pipeline miles were 

assessed, the repair condition identified, and when the condition was actually repaired. The lag 

between assessment and repair is likely greater for scheduled repairs than for immediate repairs.

During this period—2004 through 2011—PHMSA also collected data on 

the frequency of incidents, failures, and leaks in high consequence 

areas.23

 

23PHMSA defines “incidents” as the release of gas from a pipeline that results in: a death 

or personal injury requiring in-patient hospitalization, estimated property damage of 

$50,000 or more, unintentional estimated gas loss of three million cubic feet or more, or 

an event that is significant in the operator’s judgment. “Leaks” are defined as the 

unintentional escape of gas from a pipeline that is not reportable as an incident. PHMSA 

defines a “failure” using the industry consensus standard developed by the American 

Society of Mechanical Engineers (ASME B31.8S), which classifies a failure as a part in 

service that has become inoperable, is still operable but is incapable of satisfactory 

performance, or that has deteriorated to the point of being unreliable or unsafe for 

continued use. See 49 C.F.R. § 191.3 and 75 Fed. Reg. 72878 (Nov. 26, 2010).

The average number of incidents in high consequence areas—
 

Page 16 GAO-13-577 Gas Pipeline Reassessment Intervals

the most serious of the three events because they can result in fatalities, 

injuries, or significant property damage—was 8 per year. When incidents 

in high consequence areas occur, they can have a significant impact in 

terms of lives lost, injuries, and property damage, as seen with the 

incident, noted earlier, in San Bruno, California.

Individual pipeline operators can use data collected through baseline 

assessments and reassessments to determine the appropriate 

reassessment interval for pipeline segments on their systems, but using 

these data once they have been aggregated to determine a national 

maximum reassessment interval is not feasible. Per PHMSA’s 

regulations,24

We were asked to compare the number of anomalies noted in PHMSA’s 

baseline assessment data with its reassessment data as part of the 

mandate for this report in the Pipeline Safety, Regulatory Certainty, and 

operators use information on risks specific to their pipeline 

and changes in anomalies previously identified to determine the 

appropriate reassessment interval for their pipeline segments in high 

consequence areas. For example, an operator told us that the company 

calculates reassessment intervals for pipeline segments in high 

consequence areas using baseline assessment and reassessment data 

(when available) to determine the remaining strength of an anomaly and a 

corrosion growth rate. Based on these calculations, corrosion should not 

grow to unsafe levels before the next reassessment. Pipeline operators 

report data to PHMSA that include the miles assessed in high 

consequence areas, conditions repaired within high consequence areas, 

and the tools used to conduct assessments. These data are reported as a 

summary of all pipeline miles for that company. Operators with both 

interstate and intrastate pipelines as well as those transporting different 

gas products are required to report on each system separately. As a 

result, the data collected by PHMSA are highly aggregated and do not 

allow comparison of a single pipeline segment over time, or the 

determination of a national maximum reassessment interval.

 

2449 C.F.R. § 192.939.

PHMSA Data Alone Cannot 

Be Used to Determine a 

Maximum Reassessment 

Interval
 

Page 17 GAO-13-577 Gas Pipeline Reassessment Intervals

Job Creation Act of 2011.25

• PHMSA’s data do not separate conditions repaired that were 

identified from baseline assessments from those identified by 

reassessments.

As described below, the assessment repair 

data collected by PHMSA lack the detail and completeness to make this 

comparison:

26

• Even if repair data were separated based on whether the condition 

repaired was identified during a baseline assessment or 

reassessment, the first round of reassessments in high consequence 

Beginning with the 2010 annual report, PHMSA has 

used a data collection form that does not require pipeline operators to 

differentiate conditions repaired based on whether the condition was 

identified during a baseline assessment or a reassessment. A PHMSA 

official told us that given the quantity of data pipeline operators are 

already required to provide to PHMSA, asking them to report 

conditions as either identified during baseline assessments or 

reassessments would significantly increase the reporting burden. 

Also, as pipeline operators begin their second round of 

reassessments, the data will not identify repairs as coming from the 

first, second, or later rounds of reassessments. The lack of detail in 

PHMSA’s data will make it impossible to compare—amongst all gas 

transmission pipeline operators or for a specific pipeline system—the 

number of repairs identified during baseline assessments to those

identified during reassessments. Therefore, looking solely at 

PHMSA’s data, an observer could not tell whether conditions repaired 

have increased or decreased as operators conduct initial and 

subsequent reassessments.

 

25PHMSA defines an “anomaly” as a deviation from the original configuration of the 

pipeline, such as a crack, change in wall thickness due to metal loss, or a dent or gouge in 

the pipe wall. PHMSA uses the term “condition” to describe anomalies that require, for 

example, immediate or scheduled repair. Since PHMSA’s data focuses on conditions or 

conditions repaired, we use these terms to refer to anomalies. See 49 C.F.R. §192.933(a), 

(c), (d)(1), (d)(2), and (d)(3).

26PHMSA’s annual report for gas transmission pipelines asks pipeline operators to report 

the total number of conditions (meeting the definition of either an immediate repair 

condition, a one-year condition, a monitored condition, or other scheduled conditions as 

defined in regulation) repaired in that calendar year within a high consequence area 

pipeline segment by the type of assessment tool used (e.g., in-line inspection, direct 

assessment, or other assessment methods).
 

Page 18 GAO-13-577 Gas Pipeline Reassessment Intervals

areas may not be complete until the end of 2019.27

Further, even if the repair data from baseline assessments and 

reassessments could be compared, these data are not sufficient to 

determine an appropriate maximum reassessment interval—such as the 

7-year reassessment interval established in the Pipeline Safety 

Improvement Act of 2002—for all operators for several reasons, including 

those listed below:

A comparison of 

the number of critical repairs identified during baseline assessments 

and reassessments would not be possible until these reassessments 

are complete.

• A decrease or increase in the number of conditions repaired would not 

necessarily indicate the appropriateness of the 7-year reassessment 

requirement. For example, according to the American Society of 

Mechanical Engineers (ASME), a decline in the number of repairs per 

mile would indicate the effectiveness of a pipeline operator’s integrity 

management plan and not that of the reassessment interval itself.

• As mentioned above, the data reported to PHMSA are highly 

aggregated. As a result, it is not possible to perform the type of 

analysis at the national level that pipeline operators use to determine 

reassessment intervals for an individual pipeline segment. For 

example, calculating a corrosion growth rate using assessment data is 

one way that pipeline operators can determine the appropriate 

reassessment interval for a pipeline segment. This calculation 

requires information about the history, condition, environment, and the 

characteristics of individual anomalies found on that individual pipeline 

segment. PHMSA’s assessment data do not have that level of 

necessary detail, so they cannot be used to determine an appropriate 

maximum reassessment interval for the entire gas transmission 

pipeline system in the United States. Instead, PHMSA’s data can 

provide descriptive information about how much pipeline mileage 

operators are assessing and how many repairs are being made.

While the repair data collected by PHMSA are not sufficient to determine 

an appropriate maximum reassessment interval for all pipelines in the 

United States, an industry standard setting organization has developed

maximum reassessment intervals of 10, 15, or 20 years that are widely 

 

27Since gas transmission pipeline operators had until December 2012 to finish baseline 

assessments, the initial round of reassessments may not be complete until 7 years later, 

or December 2019.
 

Page 19 GAO-13-577 Gas Pipeline Reassessment Intervals

accepted as balanced and transparent. As we reported in 2006,28 ASME 

developed an industry consensus standard—subsequently approved by 

the American National Standards Institute29 —on maximum reassessment 

intervals for all safety risks (including corrosion damage) that PHMSA 

incorporated into its regulations. ASME based this standard 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. In addition, it is federal policy to encourage the use of industry 

consensus standards: Congress expressed a preference for technical 

standards developed by consensus bodies over agency-unique standards 

in the National Technology Transfer and Advancement Act of 1995.30 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.

 

28GAO, Natural Gas Pipeline Safety: Risk-Based Standards Should Allow Operators to 

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

8, 2006).

29The 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.

30Pub. L. No. 104-113, §12, 110 Stat. 782 (1996).
 

Page 20 GAO-13-577 Gas Pipeline Reassessment Intervals

Maximum reassessment intervals—such as the 7-year reassessment 

requirement—provide a safeguard and allow regulators and operators to 

identify and address problems on a continual basis. The 7-year 

reassessment requirement as well as the reassessment intervals noted in 

the industry consensus standards represent the maximum number of 

years between reassessments. If pipeline conditions dictate more 

frequent reassessments, then pipeline operators must perform 

reassessments more frequently in order to comply with PHMSA’s integrity 

management regulations. Both the 7-year reassessment requirement and 

the maximum reassessment intervals noted in the industry consensus 

standards are likely to identify problems before they result in leaks or 

ruptures. For example, according to the industry consensus standards, it 

typically takes longer than the 10, 15, or 20 years specified in the 

standards for corrosion problems to result in a leak or rupture. Because 

the 7-year reassessment requirement is a more frequent interval than 

those in the industry consensus standards, it provides greater assurance 

that operators are regularly monitoring their pipelines to identify and 

address threats before they result in a leak or rupture.

Regulators and operators we spoke with indicated that a maximum 

reassessment interval should exist and saw benefits to conducting 

periodic assessments of gas transmission pipelines. Regulators—both at 

the federal and state levels—told us that overseeing a maximum 

reassessment interval is rather straightforward. For example, an inspector 

can use operators’ records to verify relatively easily whether the operator 

completed an assessment on time. Operators we spoke with also support 

maximum reassessment intervals, telling us that in performing baseline 

assessments and reassessments they have obtained valuable knowledge 

of the condition of their pipeline systems, and that a maximum 

The 7-Year 

Reassessment 

Requirement Provides 

a Safeguard, but Is 

Not Fully Consistent 

with Risk-Based 

Practices 

Maximum Reassessment 

Intervals Provide a 

Safeguard
 

Page 21 GAO-13-577 Gas Pipeline Reassessment Intervals

reassessment interval can provide a safeguard to compel poor performing 

operators to improve the integrity of their pipeline systems.

Risk-based management has several key characteristics that help to 

ensure safety—it (1) uses information to identify and assess risks; (2) 

prioritizes risks so that resources may be allocated to address higher 

risks first; (3) promotes the use of regulations, policies, and procedures to 

provide consistency in decision making; and (4) monitors performance. 

The gas integrity management program is based on risk-based 

management practices. For example, it requires operators to integrate 

information from various sources, such as assessments, to identify the 

risks specific to their pipelines. To prioritize risks for resource allocation, 

the gas integrity management program focuses on high consequence 

areas and required operators to assess the riskiest segments of their 

pipelines first. Our past work has shown the benefits of risk-based 

management, including the integrity management program.31

However, the 7-year reassessment requirement—which was established 

by the Pipeline Safety Improvement Act of 2002 and is just one 

component of the gas integrity management program—is not fully 

consistent with risk-based management practices. For example, the 7-

year reassessment requirement does not permit operators to apply the 

information that they have collected from their assessments: even though 

operators must determine an appropriate reassessment interval based on 

the threats facing their pipelines in high consequence areas, they must 

reassess those pipelines at least for corrosion threats every 7 years 

regardless of the risks identified. While operators can currently use 

data—such as pipeline conditions and other information learned from 

previous assessments—to determine that more frequent assessments 

than every 7 years are required (e.g., every 5 years), operators cannot 

For 

instance, we reported in 2006 that the integrity management program 

benefits public safety by supplementing existing safety requirements with 

risk-based management principles that focus on safety risks in high 

consequence areas.

 

31GAO, Natural Gas Pipeline Safety: Risk-Based Standards Should Allow Operators to 

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

8, 2006); and Natural Gas Pipeline Safety: Integrity Management Benefits Public Safety, 

but Consistency of Performance Measures Should be Improved, GAO-06-946

(Washington, D.C.: Sept. 8, 2006).

The 7-Year Reassessment 

Requirement Is Not Fully 

Consistent with RiskBased Practices
 

Page 22 GAO-13-577 Gas Pipeline Reassessment Intervals

bypass the 7-year reassessment requirement if they have data that 

shows reassessment intervals longer than 7 years are justified (e.g., 

every 10 years). Rather, operators that choose to establish reassessment 

intervals beyond 7 years must still conduct some type of reassessment at 

least every 7 years in order to comply with the 2002 act. PHMSA officials 

told us that the 7-year reassessment requirement does not take into 

account risk, and while it may be an appropriate interval length for some 

pipeline systems, it is too short or too long for other systems.

In contrast to these regulations, there are no statutory requirements that 

limit risk-based reassessment intervals for operators of a different type of 

pipeline, that of hazardous liquids. Under PHMSA’s regulations for the 

hazardous liquid integrity management program, operators must perform 

assessments of their pipelines within high consequence areas following a 

maximum reassessment interval. This reassessment interval—which, 

unlike the gas transmission pipeline reassessment interval, was 

established by a PHMSA rulemaking using a data analysis32

In 2006, we reported that most of the operators we contacted preferred 

that reassessment intervals be based on the conditions and 

characteristics of the pipeline segment. In general, the industry 

associations we spoke with for this report also preferred risk-based 

reassessment intervals instead of the current 7-year reassessment 

requirement. In addition, 21 of the 27 operators we spoke with for this 

report indicated that they prefer a risk-based reassessment interval 

requirement. According to some of these operators, complying with the 

—can be 

extended if an operator can provide an engineering basis to do so; that is, 

operators have the ability to use the information learned from prior 

assessments and other efforts to identify and assess the risks facing its 

pipelines and determine that a longer reassessment interval is justified. 

Because the 7-year reassessment requirement for gas transmission 

pipelines was established by statute and not in a PHMSA rulemaking, 

PHMSA does not have the authority to modify this requirement without 

congressional action.

 

32Per PHMSA’s regulations, hazardous liquid pipelines have a maximum reassessment 

interval of 5 years. This reassessment interval was determined, in part, through an 

analysis of available data. PHMSA established integrity management requirements for 

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

and for operators with less than 500 miles in January 2002. Prior to enactment of the 

Pipeline Safety Improvement Act of 2002, PHMSA was exploring a rulemaking for integrity 

management for gas transmission pipelines.
 

Page 23 GAO-13-577 Gas Pipeline Reassessment Intervals

current 7-year reassessment requirement without the ability to use riskbased reassessment intervals beyond 7 years may not be an efficient use 

of their resources. For example, some operators told us that if they could 

reassess their pipeline segments less frequently than every 7 years 

without negatively impacting safety, they could potentially devote more 

resources to other safety tasks.

PHMSA’s gas transmission integrity management regulations include 

provisions that could make reassessments more risk-based, but these 

efforts have not seen widespread use, primarily due to the 2002 act’s 7-

year reassessment requirement.

• PHMSA’s regulations permit operators to use confirmatory direct 

assessment to comply with the 2002 act. Operators that choose to 

use confirmatory direct assessment are those that have established 

reassessment intervals greater than 7 years but no more than those 

noted in the industry consensus standards. These operators perform 

a confirmatory direct assessment at year 7 to look for corrosion 

threats only, followed by a reassessment at the interval the operator 

established for all threats facing the pipeline. According to PHMSA 

officials, confirmatory direct assessment was included in the 

regulations to better align with risk management principles. However, 

of the 27 operators with whom we spoke, only 5 told us that they 

completed or planned to conduct confirmatory direct assessment. 

According to some of the operators we spoke with, confirmatory direct 

assessment—which looks for corrosion damage only—can be just as 

costly and time-consuming as performing a reassessment for all 

safety risks and, therefore, the operators chose to perform a 

reassessment at the 7-year mark instead. Most of the regulators we 

spoke with—both at the federal and state levels—also noted that 

operators are generally not using confirmatory direct assessment.

• PHMSA’s regulations allow operators with ‘exceptional performance’ 

to deviate from some of the requirements of the integrity management 

regulations.33

 

3349 C.F.R. § 192.913.

These operators must have completed at least two 

assessments (i.e., a baseline assessment and a reassessment) and 

have remediated all anomalies found in the most recent assessment. 

An operator satisfying all of the exceptional performance criteria is 

generally permitted to deviate from most integrity management 

regulations. However, in order to comply with the 2002 act and 
 

Page 24 GAO-13-577 Gas Pipeline Reassessment Intervals

PHMSA’s regulations, the operator must still perform a confirmatory 

direct assessment at least every 7 years. None of the operators we 

spoke with are pursuing the exceptional performance option, with 

most indicating that because they must complete a confirmatory direct 

assessment to identify corrosion problems every 7 years, this option 

holds little, if any, benefit.

Although PHMSA generally agreed in the past that risk-based standards 

would allow operators to better tailor reassessments to pipeline threats, 

PHMSA cannot change the current 7-year reassessment requirement 

unless congressional action occurs because the requirement is in statute. 

The reassessment requirement is in the regulation pursuant to the 

requirement in the Pipeline Safety Improvement Act of 2002. In 2006, we 

recommended that this statutory requirement be amended to permit 

operators to reassess at intervals based on risk factors, technical data, 

and engineering analyses.34

In addition to requiring a statutory change, PHMSA officials noted that a 

number of current challenges could potentially be exacerbated by 

implementing risk-based reassessment intervals. For instance, inspecting 

and evaluating risk-based reassessment intervals beyond 7 years could 

 

34GAO-06-945. 

Implementing RiskBased Reassessment 

Intervals beyond 7 

Years Could 

Exacerbate Current 

Challenges and Would 

Benefit from More 

Information on 

Resource 

Requirements 

Changes to the 7-Year 

Reassessment 

Requirement Requires 

Congressional Action and 

Could Exacerbate Current 

Issues with Reviewing and 

Justifying Reassessment 

Intervals
 

Page 25 GAO-13-577 Gas Pipeline Reassessment Intervals

create additional workload, staffing, and expertise challenges for 

regulators, such as PHMSA and state pipeline safety offices, for example:

• PHMSA officials told us that allowing all operators to participate in 

risk-based reassessment intervals beyond 7 years could add 

significantly to the agency’s workload in terms of inspecting operators’ 

integrity management programs, including review of their calculated 

reassessment intervals. For instance, these evaluations could require 

inspectors to spend more time and resources than currently, which 

could affect the number of inspections conducted overall. Moreover, 

PHMSA has already experienced some workload problems with 

inspections, which could be worsened by allowing operators to use 

risk-based reassessment intervals beyond 7 years. For example, in 

2012, the Department of Transportation’s Office of the Inspector 

General reported that PHMSA has recently accumulated a backlog of 

integrity management inspections for hazardous liquid operators, 

caused in part by the agency redirecting resources to fulfill other 

inspection requirements.35 In response, beginning in 2013, the agency 

will implement a new approach to inspections, called integrated 

inspections,36

 

35U.S. Department of Transportation Office of Inspector General, Hazardous Liquid 

Pipeline Operators’ Integrity Management Programs Need More Rigorous PHMSA 

Oversight, Report no. AV-2012-140, (June 18, 2012). According to the Inspector General’s 

report on hazardous liquids, PHMSA would have needed to complete 49 integrity 

management inspections in 2012 to clear its backlog; however, the agency averages only 

around 22 integrity management inspections per year.

where an inspector may use data and information about 

a specific operator and pipeline system to custom-build a list of 

regulatory requirements to evaluate during inspection. For these 

integrated inspections, integrity management requirements would be 

one of several regulatory requirements inspectors could choose to 

focus on. However, the Inspector General’s report noted that 

PHMSA’s proposed schedule to implement a number of 

enhancements to its inspection program is ambitious and challenging, 

36The Office of Pipeline Safety began pilot testing integrated inspections in 2008. 

Integrated inspections are a data-driven process allowing the Office to focus inspection 

resources on the regulatory provisions addressing the greatest identified risks. Integrated 

inspections would contain integrity management inspection requirements, according to 

PHMSA officials. According to PHMSA’s gas integrity management inspection manual, 

which includes inspection protocols, the purpose of the inspection is not to perform a 

quality check of every integrity related activity. Instead, inspectors will typically perform an 

inspection of selected operator records sufficient in breadth and depth to give the 

inspection team adequate understanding of the degree of compliance.
 

Page 26 GAO-13-577 Gas Pipeline Reassessment Intervals

and until PHMSA successfully completes the transition, the agency 

may not be able to ensure sufficient and consistent oversight of all 

integrity management programs.

• Officials from state pipeline safety offices we met with noted potential 

concerns with staffing and training to effectively evaluate risk-based 

reassessment intervals. For example, some state pipeline safety 

officials suggested that they would need dedicated staff to evaluate 

operators’ results and analyses, while other state officials cited the 

current difficulty with enrolling in PHMSA training courses due to long 

waiting lists. Also, some operators we interviewed expressed concern 

that inspectors from state pipeline safety offices may lack sufficient 

training to review these analyses. For example, although state officials 

currently inspect operators’ integrity management programs, some 

operators told us that inspectors do not typically challenge their 

reassessment interval calculations.

• Regulating risk-based reassessment intervals beyond 7 years could 

be particularly challenging for PHMSA and state pipeline safety offices 

because there is a lack of guidance for operators to perform risk 

modeling. As a result, operators could use a variety of methodologies 

to calculate appropriate reassessment intervals for pipeline systems 

and even individual segments. The level of detail and review required 

by regulators overseeing these operators would vary depending on 

the sophistication of the operators’ analyses.

While current regulations require operators to use engineering and risk 

analyses to determine the frequency at which reassessments must be 

conducted, operators could face additional challenges in justifying and 

calculating risk-based reassessment intervals beyond 7 years. Some 

operators told us that risk-based reassessment intervals beyond 7 years 

would likely be more labor-intensive and data-driven than the current 

regulatory environment. For example, operators would likely have to 

provide PHMSA more analyses to justify their calculated reassessment 

intervals than currently. Based on our interviews, operators appear to 

vary in the extent to which they currently calculate reassessment intervals 

and use the results of the data analyses, for example:

• Some operators we spoke with told us that they perform a less 

rigorous determination of their reassessment intervals and default to 

the 7-year interval if they determine that there are no problems with 

their pipelines. Also, one operator told us that unless evidence of 

corrosion is found on the pipeline segment, the operator does not 

perform a comprehensive calculation of the reassessment interval.

• Some operators we spoke with calculated reassessment intervals 

resulting in 7 years, but still chose to reassess their pipelines more 
 

Page 27 GAO-13-577 Gas Pipeline Reassessment Intervals

frequently than their calculations due to identified conditions such as 

pipeline coating issues. While such a decision prioritizes the safety of 

the pipeline, it also illustrates some of the potential subjectivity 

involved with reassessment interval calculations, which may have 

accounted for such conditions, but did not ultimately determine a 

shorter interval in the analysis. For example, some PHMSA officials 

told us that oftentimes there is more than one correct conclusion 

based on pipeline data and some operators will choose a more 

conservative approach than others and vice versa. Further, some 

technical experts told us that risk-based reassessment intervals would 

require a higher level of skill and analysis beyond some operators’ 

current capabilities, thus forcing the operator to seek the assistance of 

contractors.

As a result, the challenges operators currently have with justifying and 

calculating reassessment intervals, partly because of a lack of guidance 

from PHMSA, could be further affected if operators are to use these types 

of analyses to justify risk-based reassessment intervals beyond 7 years. 

Without guidance for operators to use in determining and calculating 

reassessment intervals, operators may use a range of approaches for 

determining the relevant risks to their systems, which could then create 

potential challenges for regulators with reviewing risk-based 

reassessment intervals beyond 7 years and ensuring oversight of these 

pipelines.
 

Page 28 GAO-13-577 Gas Pipeline Reassessment Intervals

In 2008, PHMSA provided a detailed statement at the request of 

Congress to explain how the agency would establish and enforce riskbased criteria for extending the 7-year reassessment interval.37 According 

to PHMSA’s proposal, it would retain the current 7-year reassessment 

requirement, but allow for the use of risk-based reassessment intervals 

on a case-by-case basis where justified. Congress did not take any action 

to address this proposal as a result of the 2008 report,38

• First, PHMSA would establish via rulemaking risk-based criteria that 

operators must meet to warrant extending their reassessment 

intervals beyond 7 years.

and PHMSA has 

neither reviewed nor updated its 2008 report to determine whether that 

report’s conclusions remain valid. However, PHMSA’s proposal outlined a 

number of steps to establish a process permitting the use of risk-based 

reassessment intervals beyond 7 years, for example:

39

• Second, interested operators would have to notify PHMSA (or a state 

pipeline safety office for an intrastate transmission pipeline) one year 

in advance of the scheduled reassessment and submit information 

demonstrating their conformance with the criteria before using riskbased reassessment intervals beyond 7 years. As shown in table 1, 

one potential criterion could require some operators to conduct 

assessments using in-line inspection or hydrostatic testing (see 

appendix II for a longer list of draft criteria provided by PHMSA).

 

37Pipeline and Hazardous Materials Safety Administration, Gas Transmission Pipeline 

Integrity Management Assessment: Proposed Reassessment Interval Extension Review, 

(Apr. 15, 2008).

38The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, however, did 

allow for a 6-month extension of the 7-year reassessment requirement if the operator 

submits written notice to the Secretary with sufficient justification of the need for the 

extension, subject to the limits of the waiver process under 49 U.S.C. § 60109(c)(5). Pub. 

L. No. 112-90, §5(e), 125 Stat. 1904, 1908 (codified at 49 U.S.C. § 60109(c)(3)(B)).

39PHMSA also proposed that if the statutory requirement was not amended, the agency 

could use the specific authority granted by Congress for operators to apply for a waiver 

(49 U.S.C. § 60109(c)(5)). For example, PHMSA would issue special permits to operators, 

allowing them to extend the assessment interval, based on the conditions of the permit. 

However, according to PHMSA’s regulations for gas transmission integrity management, 

the agency can only grant waivers of the 7-year maximum reassessment interval either to 

maintain local product supply or due to the lack of internal inspection devices. As a result, 

PHMSA’s own regulations do not allow for additional types of waivers. 49 C.F.R. § 

192.943.

PHMSA Has Previously 

Considered an Approach 

to Implementing RiskBased Reassessment 

Intervals beyond 7 Years, 

but More Information on 

Resource Requirements Is 

Needed
 

Page 29 GAO-13-577 Gas Pipeline Reassessment Intervals

Table 1: Examples of Potential Criteria for Risk-Based Pipeline Reassessment Intervals

Potential criteria examples

• If the pipeline operates at pressures that are greater than or equal to 30 percent of specified minimum yield strength it must have 

been assessed using in-line inspection or hydrostatic testing.

• Few or no significant corrosion repairs have been made in the covered segment since the last integrity assessment.

• Causes of previously identified significant corrosion defects have been corrected.

• Pipeline is coated and cathodically protected (a technique to reduce the corrosion of a metal surface) and be in good condition. 

• No history of pipeline cracking due to the combined influence of stress and a corrosive environment.

• Assumed corrosion growth rate is justified and supports the longer reassessment interval. Calculations of the remaining time 

frame before pipeline failure are conservative and demonstrate safety for an extended interval.

• Pipeline must have been constructed after 1970 unless demonstration of good condition is provided.

• Environmental conditions in which the affected pipeline segment is located must not be unusually conducive to corrosion.

Source: PHMSA.

Note: As noted above, PHMSA has neither reviewed nor updated its 2008 report to determine 

whether that report’s conclusions remain valid. For example, according to PHMSA, the 30 percent of 

specified minimum yield strength figure shown in the first criteria above does not reflect PHMSA’s 

current regulatory requirements.

• Third, PHMSA would review all the notifications to determine whether 

the criteria in the rule have been met.40

PHMSA officials expected that operators of some types of pipelines would 

be more likely to use risk-based reassessment intervals beyond 7 years 

than others. For example, PHMSA cited operators that have 

demonstrated that their pipe is sound and that their engineering and risk 

analysis do not indicate the likelihood of time-dependent integrity 

problems occurring during a reassessment interval beyond 7 years. 

Although operators support the idea of using risk-based reassessment 

intervals beyond 7 years, it is not clear how many operators would be 

For example, operators would 

need to demonstrate through analyses and documentation that their 

pipeline segments meet each criterion or provide substantial 

justification that any failure to meet a criterion does not increase the 

risk of corrosion in the segment. PHMSA would also consider in its 

review the specific location of the pipeline segments, the potential 

consequences if an accident were to occur at that location, and the 

compliance and overall performance history of the operator.

 

40PHMSA conducted a public meeting in January 2008 to describe the criteria it would use 

to gauge the suitability of using risk-based reassessment intervals beyond 7 years where 

justified. According to PHMSA’s proposal, the agency would develop additional detailed 

guidance concerning the information necessary to demonstrate conformance with the 

criteria.
 

Page 30 GAO-13-577 Gas Pipeline Reassessment Intervals

able to meet the potential criteria established by PHMSA, and PHMSA 

officials could not estimate the number either. For example, not all 

operators can conduct assessments using in-line inspection or hydrostatic 

testing, which is one of PHMSA’s proposed criteria for using risk-based 

reassessment intervals. According to the proposal, operators would have 

to meet each of the criteria. As a result, the mileage of pipelines that 

would be affected by allowing risk-based reassessment intervals beyond 

7 years is currently unknown.

In light of the uncertain potential effect on resources and expertise for 

both regulators and operators, an effort to implement risk-based 

reassessment intervals beyond 7 years may benefit first from PHMSA 

obtaining additional information regarding the resource requirements 

needed prior to a rule change, such as how the Office of Pipeline Safety 

initially established integrity management regulations. For example, the 

Accountable Pipeline Safety and Partnership Act of 1996 directed the 

Office of Pipeline Safety to establish a demonstration program to test a 

risk management approach to pipeline safety.41 Under the program 

envisioned by the legislation, the Secretary sought voluntary participation 

by interstate natural gas and hazardous liquid transmission operators in 

good standing to demonstrate company-specific risk management plans. 

The Secretary then completed a rulemaking that outlined the 

demonstration plan’s elements and provided opportunities for full public 

participation in the process. As a result, partly on the basis of the 

agency’s experience with the risk management demonstration program, 

the agency moved forward with a new regulatory approach, known as 

integrity management. Similarly, as noted above, PHMSA produced a 

report at the request of Congress explaining how the agency would 

establish and enforce risk-based criteria for extending the 7-year 

reassessment interval. In effect, efforts such as these allowed the agency 

to obtain preliminary results and information on the proposed rule such as 

the potential benefits and impacts under a variety of conditions before 

making a change.

 

41Pub. L. No. 104-304, § 5, 110 Stat. 3793, 3798 (1996).
 

Page 31 GAO-13-577 Gas Pipeline Reassessment Intervals

Gas transmission pipeline assessments and reassessments have 

resulted in critical repairs being made. While the 7-year reassessment 

requirement has provided a safeguard by helping to identify these 

problems before they cause leaks or ruptures, the prescriptive 7-year 

reassessment requirement is not fully consistent with the characteristics 

of risk-based management promoted by the Pipeline Safety Improvement 

Act of 2002. PHMSA has generally agreed that risk-based reassessment 

intervals would allow operators to better tailor reassessments to pipeline 

threats and operators support this concept. Risk-based reassessment 

intervals beyond 7 years would allow operators to use the information 

they have collected about their pipeline systems to focus resources on 

areas of greatest importance.

PHMSA drafted a process to establish and enforce risk-based criteria for 

the potential use of risk-based reassessment intervals in 2008. While this 

process would be more consistent with risk management practices, 

permitting operators to use risk-based reassessment intervals beyond 7 

years would not be without challenges, even if justified using an 

engineering basis. First, Congress would have to amend the statutory 

requirement mandating the 7-year reassessment interval. In 2006, we 

recommended that this statutory requirement be amended to permit 

operators to reassess at intervals based on risk factors, technical data, 

and engineering analyses. If Congress were to amend the statute, both 

federal and state regulators as well as operators anticipate that 

overseeing and determining risk-based reassessment intervals beyond 7 

years may create workload, staffing, and expertise challenges over what 

is currently required. Further, there is a lack of guidance to assist 

regulators and operators in developing the risk models currently used to 

calculate reassessment intervals. Without such guidance, operators could 

use a range of approaches for determining the relevant risk to gas 

transmission pipelines, potentially creating challenges with reviewing and 

justifying reassessment intervals.

Given these potential challenges, more information might help decisionmakers better understand the resource requirements needed in allowing 

risk-based reassessment intervals beyond 7 years. In this context, 

conducting a study or developing a legislative proposal for a pilot 

program, in consultation with Congress, to examine the impact on 

regulators and operators from the use of risk-based reassessment 

intervals beyond 7 years could help stakeholders—including regulators, 

operators, and decision-makers—determine the resource demands of 

inspecting and evaluating these efforts. A full evaluation of the challenges 

to implementing risk-based reassessment intervals beyond 7 years and 

Conclusions 
 

Page 32 GAO-13-577 Gas Pipeline Reassessment Intervals

their associated resource requirements could help to identify the most 

prudent and effective way to implement risk-based reassessment 

intervals. Such an evaluation could help to ensure that the challenges 

regulators and operators claim they may face from this change would not 

negatively affect safety. Further, a study—similar to the 2008 report 

PHMSA prepared at the request of Congress and incorporating lessons 

learned since publication of that report—or a legislative proposal for a 

pilot program—similar to the one used in developing the integrity

management program—could allow regulators to develop guidance on 

calculating risk-based reassessment intervals as well as determine the 

impact of these reassessment intervals. As the debate about the use of 

risk-based reassessment intervals continues, it is clear that more 

information is needed to further the understanding and discussion about 

how to address the potential challenges to using risk-based 

reassessment intervals beyond 7 years before any change occurs.

To improve how operators calculate reassessment intervals, we 

recommend that the Secretary of Transportation direct the Administrator 

for the Pipeline and Hazardous Materials Safety Administration to develop 

guidance for operators to use in determining risks and calculating 

reassessment intervals.

To better identify the resource requirements needed to implement riskbased reassessment intervals beyond 7 years for gas transmission 

pipelines, we recommend that the Secretary of Transportation direct the 

Administrator for the Pipeline and Hazardous Materials Safety 

Administration to collect information on the feasibility of addressing the 

potential challenges of implementing risk-based reassessment intervals 

beyond 7 years, for example by preparing a report or developing a 

legislative proposal for a pilot program, in consultation with Congress, that 

studies the impact to regulators and operators of a potential rule change.

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

for review and comment. The department did not agree or disagree with 

the recommendations, but provided technical comments that we

incorporated as appropriate.

Recommendations for 

Executive Action

Agency Comments
 

Page 33 GAO-13-577 Gas Pipeline Reassessment Intervals

We are sending copies of this report to relevant congressional 

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

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

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

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

me at (202) 512-2834 or flemings@gao.gov. Contact points for our 

Offices of Congressional Relations and Public Affairs may be found on 

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

report are listed in appendix III.

Susan A. Fleming

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

Methodology

Page 34 GAO-13-577 Gas Pipeline Reassessment Intervals

Our work for this report focused on gas transmission pipelines in high 

consequence areas and the requirement to assess these pipeline 

segments at periodic intervals. In particular, this report examines: (1) the 

extent to which the Pipeline and Hazardous Materials Safety 

Administration’s (PHMSA) assessment data provides information on 

repairs made and the appropriateness of the 7-year reassessment 

requirement, (2) the impact of the 7-year reassessment requirement on 

regulators and operators, and (3) the potential challenges of 

implementing risk-based reassessment intervals beyond 7 years.

To address the extent to which PHMSA’s assessment data provides 

information on repairs and the appropriateness of the 7-year 

reassessment requirement, we reviewed PHMSA’s regulations, prior 

GAO reports, and PHMSA data on gas transmission pipelines. We 

analyzed the data reported to PHMSA by pipeline operators on, among 

other things, age and operating pressure of transmission pipelines; 

pipeline miles assessed; tools used to conduct assessments; immediate 

and scheduled conditions found during assessments and subsequently 

repaired; and incidents, leaks, and failures on gas transmission pipelines 

in high consequence areas.

We used two PHMSA data sources in our data analysis: the Gas Integrity 

Management Semi-Annual Performance Measures Reports from 2004 

through 2009 and the Annual Reports on Natural and Other Gas 

Transmission and Gathering Pipeline Systems from 2010 and 2011. From 

2004 to 2009, PHMSA collected information on miles assessed, incidents, 

leaks, and failures in high consequence areas using the Gas Integrity 

Management Semi-Annual Performance Measures Report. Through this 

report, PHMSA collected data on baseline assessments and started 

collecting data on reassessments in 2008. In 2010, PHMSA discontinued 

the Gas Integrity Management Semi-Annual Performance Measures 

Report and merged it with the Annual Report on Natural and Other Gas 

Transmission and Gathering Pipeline Systems. The updated Annual 

Report on Natural and Other Gas Transmission and Gathering Pipeline 

Systems added questions on pipeline miles that were baseline assessed 

and reassessed; tools used to conduct assessments; conditions identified 

and repaired as a result of assessments; and incidents, leaks, and 

failures in high consequence areas. One important change in the updated 

Annual Report was PHMSA’s new approach to documenting conditions 

and repairs identified by baseline assessments and reassessments. Prior 

to 2010, pipeline operators reported the number of repairs made on 

pipelines to fix problematic conditions identified by the assessments—a 

single repair could mitigate multiple problems. For 2010 and later, 

Appendix I: Objectives, Scope, and 

Methodology 
Appendix I: Objectives, Scope, and 

Methodology

Page 35 GAO-13-577 Gas Pipeline Reassessment Intervals

pipeline operators were required to report the number of repaired 

conditions. Since operators have to report the actual number of problems 

found and repaired, PHMSA expected the number of reported repairs to 

spike. Due to this reporting change, we cannot compare repair data from 

2004 to 2009 to repair data reported in 2010 and later. To assess the 

reliability of PHMSA’s gas transmission pipeline data, we spoke with 

agency officials about data quality control procedures and reviewed 

relevant documentation. We determined that the data were sufficiently 

reliable for the purposes of this report, specifically to provide background 

information and to describe repairs made in high consequence areas. To 

ensure the accuracy of our data analysis, we internally reviewed our 

calculations and shared preliminary results with PHMSA to ensure that 

we analyzed its data appropriately.

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

regulators and operators, we reviewed relevant legislation and PHMSA 

regulations on integrity management. We also interviewed federal and 

state regulators, industry associations, gas transmission pipeline 

operators, pipeline safety advocacy and environmental groups, research 

firms, a state regulatory association, and technical experts. We selected 

27 pipeline operators to interview based on our review of PHMSA data, 

specifically looking for pipeline operators with gas transmission pipeline 

miles in high consequence areas. We then divided pipeline operators into 

six groups based on their mileage in high consequence areas and 

whether they had conducted reassessments. We chose 3 to 5 operators 

from each of the six groups, with the goal of ensuring diversity across 

these and several other characteristics, including the number of recent 

incidents caused by corrosion and their geographic location. The 

information obtained in these interviews is not generalizable to the entire 

population of pipeline operators. We also selected a non-generalizable 

sample of eight state pipeline safety offices using PHMSA data to, for 

example, identify states with relatively high pipeline mileage while also 

achieving geographic diversity. Five of the states we spoke with serve as 

interstate agents for PHMSA.42

 

42PHMSA may authorize states to act as its agent through an agreement to inspect 

interstate pipelines, but PHMSA retains responsibility for enforcement of regulations.

PHMSA currently has agreements with nine state agencies to act as interstate agents for 

gas transmission pipelines.

To learn about the operations of a gas 

transmission pipeline and the logistics of conducting an assessment, we 

made two site visits to view a pipeline under construction in Manassas, 
Appendix I: Objectives, Scope, and 

Methodology

Page 36 GAO-13-577 Gas Pipeline Reassessment Intervals

Virginia, and to view an in-line inspection tool being used on a pipeline in 

Rockville, Maryland.

To determine the potential challenges of implementing risk-based 

reassessment intervals beyond 7 years, we reviewed PHMSA 

documents. We also questioned federal and state regulators, industry 

associations, gas transmission pipeline operators, pipeline safety 

advocacy and environmental groups, research firms, a state regulatory 

association, and technical experts on the extent pipeline operators use 

risk to determine reassessment intervals under the current system, as 

well as how expanding the use of risk-based reassessment intervals 

beyond 7 years would impact operators and regulators. We collected 

additional data from three pipeline operators on their experiences in 

calculating reassessment intervals and conducting reassessments. We 

selected these three pipeline operators by using PHMSA data to identify 

gas transmission pipeline operators with different ranges of mileage in 

high consequence areas. We then selected operators that had completed 

at least some reassessments and looked for diversity in the following 

categories: geographic location, number of pipeline repairs, and tools 

used to complete assessments.

We interviewed representatives from each of the following organizations:

Federal Government

• Department of Transportation, Pipeline and Hazardous Materials 

Safety Administration

• Headquarters

• Eastern Regional Office

• Central Regional Office

• Southern Regional Office

• Southwest Regional Office

• Western Regional Office

• National Transportation Safety Board

State Pipeline Safety Offices

Arizona Office of Public Safety

California Public Utilities Commission

Michigan Public Service Commission

New York State Department of Public Service

Organizations 

Contacted 
Appendix I: Objectives, Scope, and 

Methodology

Page 37 GAO-13-577 Gas Pipeline Reassessment Intervals

North Carolina Utilities Commission

Public Utilities Commission of Ohio

Railroad Commission of Texas

West Virginia Public Service Commission

Industry Associations

American Gas Association

Inline Inspection Association

Interstate Natural Gas Association of America

Pipeline Operators

Alaska Pipeline Company

American Midstream (Tennessee River), LLC

ARCO Western Gas Pipeline Company

Atmos Pipeline—Texas

Colonial Gas Company (Lowell Division)

Columbia Gas of Ohio, Inc.

Gas Transmission Northwest Corporation

Gulfstream Natural Gas System, LLC

Hampshire Gas Company

KO Transmission Company

Massachusetts Wholesale Electric Company

MidContinent Express Pipeline LLC

Mojave Pipeline Operating Company

National Fuel Gas Supply Corporation

Northwest Pipeline Corporation

Ohio Valley Gas Corporation

Peco Energy Company

Questar Gas Company

San Diego Gas and Electric Company

Silicon Valley Power

Southcross Gulf Coast Transmission, LTD

Tennessee Gas Pipeline Company

Texas Eastern Transmission LP

UCAR Pipeline, Inc.

Viking Gas Transmission Company

Washington Gas Light Company

Williams Gas Pipeline—Transco 
Appendix I: Objectives, Scope, and 

Methodology

Page 38 GAO-13-577 Gas Pipeline Reassessment Intervals

Pipeline Safety Advocacy and Environmental Groups

Common Ground Alliance

Pipeline Safety Trust

The Wilderness Society

Research Firms

Gas Technology Institute

Pipeline Research Council International

State Regulatory Association

National Association of Pipeline Safety Representatives

Technical Experts

American Society of Mechanical Engineers

Kiefner and Associates, Inc.

National Association of Corrosion Engineers

WKM Consultancy
Appendix II: Potential Criteria for Risk-Based 

Reassessment Intervals

Page 39 GAO-13-577 Gas Pipeline Reassessment Intervals

In 2008, Congress requested that the Pipeline and Hazardous Materials 

Safety Administration (PHMSA) provide a detailed statement to explain 

how the agency would establish and enforce risk-based criteria for 

extending the 7-year reassessment interval. As part of that request, 

PHMSA drafted potential criteria that operators would have to meet in 

order to use risk-based reassessment intervals beyond 7 years.43

• If the pipeline operates at pressures that are greater than or equal to 

30 percent of specified minimum yield strength, it must have been 

assessed using in-line inspection or hydrostatic testing.

PHMSA 

noted that the criteria may be further refined as potential rulemaking 

proceeds. The draft criteria include:

• Most recent in-line inspection assessment shows pipeline to be in 

good condition. Few conditions meeting immediate repair criteria were 

found and the causative corrosion mechanisms have been identified 

and addressed.

• Most recent pressure test meets integrity management requirements 

and resulted in few leaks/failures or pressure reversals.

• Few or no significant corrosion repairs have been made in the 

covered segment since the last integrity assessment.

• Causes of previously identified significant corrosion defects have 

been corrected.

• No history of selective seam corrosion (a specialized form of corrosion 

associated with older pipelines), or microbiologically induced 

corrosion (a mode of corrosion incorporating microbes that react and 

cause the corrosion or influence other corrosion processes of metallic 

materials).

• Pipeline transports tariff quality dry gas (almost pure methane), with 

limited upsets introducing electrolyte or other contaminants, in which 

case internal corrosion risk has been managed.

• Pipeline is coated and cathodically protected (a technique to reduce 

the corrosion of a metal surface) and be in good condition. Coating 

must meet the requirements in 49 C.F.R. § 192.461 and be in good 

condition. Cathodic protection must be demonstrated generally 

effective.

• No history of stress corrosion cracking (the cracking induced from the 

combined influence of tensile stress and a corrosive environment).

 

43Pipeline and Hazardous Materials Safety Administration, Gas Transmission Pipeline 

Integrity Management Assessment: Proposed Reassessment Interval Extension Review, 

(Apr. 15, 2008).

Appendix II: Potential Criteria for Risk-Based 

Reassessment Intervals
Appendix II: Potential Criteria for Risk-Based 

Reassessment Intervals

Page 40 GAO-13-577 Gas Pipeline Reassessment Intervals

• Assumed corrosion growth rate is justified and supports the longer 

reassessment interval. Calculations of remaining time frame before 

pipeline failure are conservative and demonstrate safety for an 

extended interval.

• Few safety related conditions, leaks, incidents, or failures have 

resulted from corrosion, and the causes have been addressed.

• History of compliance with corrosion control, integrity management, 

operator qualification, and drug and alcohol testing regulations is 

good.

• Public awareness program meets the requirements in 49 C.F.R. § 

192.616.

• No open corrective action orders or significant enforcement actions 

related to corrosion control program deficiencies affecting the involved 

pipeline segments.

• Pipeline must have been constructed after 1970 unless demonstration 

of good condition is provided.

• Environmental conditions in which the affected pipeline segment is 

located must not be unusually conducive to corrosion.
Appendix III: GAO Contact and Staff 

Acknowledgments

Page 41 GAO-13-577 Gas Pipeline Reassessment Intervals

Susan A. Fleming, (202) 512-2834, or flemings@gao.gov. 

In addition to the contact named above, Sara Vermillion (Assistant 

Director), Sarah Arnett, Russell Burnett, Leia Dickerson, Colin Fallon, 

David Hooper, Joshua Ormond, Daniel Paepke, Madhav Panwar, Anne 

Stevens, and Adam Yu made key contributions to this report.

Appendix III: GAO Contact and Staff 

Acknowledgments 

GAO Contact

Staff 

Acknowledgments 

(541097)
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