United States Government Accountability Office

GAO Testimony 

Before the Subcommittee on Energy and 

Air Quality, Committee on Energy and 

Commerce, House of Representatives

GAS PIPELINE SAFETY

Views on Proposed 

Legislation to Reauthorize 

Pipeline Safety Provisions 

Statement for the Record by 

Katherine Siggerud, Director 

Physical Infrastructure Issues 

Submitted August 4, 2006

 

GAO-06-1027T 
What GAO Found

United States Government Accountability Office

Why GAO Did This Study

Highlights

Accountability Integrity Reliability

August 4, 2006

GAS PIPELINE SAFETY

Views on Proposed Legislation to 

Highlights of GAO-06-1027T, a testimony Reauthorize Pipeline Safety Provisions 

before the Subcommittee on Energy and 

Air Quality, Committee on Energy and 

Commerce, House of Representatives 

The Pipeline Safety Improvement

Act of 2002 established a risk-based

program for gas transmission 

pipelines—termed integrity

management—which requires 

pipeline operators to identify areas 

where the consequences of a

pipeline incident would be the 

greatest, such as highly populated

areas. Operators must assess 

pipelines in these areas for safety

threats (such as corrosion), repair 

or replace defective segments, and 

reassess their pipelines at least 

every 7 years. Under the Pipeline

and Hazardous Materials Safety

Administration’s (PHMSA) 

regulations, operators must

reassess their pipelines for 

corrosion at least every 7 years and

for all safety threats at least every 

10, 15, or 20 years. State pipeline 

safety agencies that assist PHMSA

are eligible to receive matching

funds up to 50 percent of the cost

of their pipeline safety programs. 

This statement is based on ongoing 

work for this Subcommittee and

for others. It focuses on three 

areas germane to current legislative

reauthorization proposals: (1) an

overall assessment of the integrity

management program, (2) the 7-

year reassessment requirement, 

and (3) provisions to increase state 

pipeline safety grants. GAO 

contacted more than 50 pipeline 

operators and a broad range of

stakeholders and surveyed state

pipeline agencies. GAO also 

reviewed PHMSA and industry

guidance and reviewed PHMSA 

pipeline performance data. 

While the gas integrity management program is still being implemented, 

early indications show that the program benefits pipeline safety. For 

example, the condition of transmission pipelines is improving as operators 

assess and repair their pipelines. As of December 31, 2005 (latest data 

available), 33 percent of the pipelines in highly populated or frequently used 

areas had been assessed and over 2,300 repairs had been completed. In 

addition, we estimate that up to 68 percent of the population that lives close 

to natural gas transmission pipelines is located in highly populated areas and 

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

safety. Furthermore, despite some uncertainty on the part of operators over 

the program’s documentation requirements, operators, gas pipeline industry 

representatives, state pipeline officials, and safety advocate representatives 

all agree that the program enhances public safety, citing operators’ improved 

knowledge of the threats to their pipelines as the primary benefit.

Although periodic reassessments of pipeline threats are beneficial, the 7-year 

reassessment requirement appears to be conservative. Through December 

2005, 76 percent of the operators (182 of 241) reporting baseline assessment 

activity to PHMSA reported that their pipelines were in good condition, 

requiring only minor repairs. Most of the problems found were concentrated 

in just 7 pipelines. These results are encouraging, since operators are

required to assess their riskiest segments first and operators are required to 

repair defects, making them safer before reassessments begin toward the 

end of the decade. There have been no deaths or injuries from corrosion 

related pipeline incidents over the past 5-1/2 years. An alternative approach 

is to permit pipeline operators to reassess their pipeline segments at 

intervals based on technical data, risk factors, and engineering analyses. 

Such an approach is consistent with the overall philosophy of the 2002 act 

and would meet its safety objectives. Under this approach, operators could 

reassess their pipelines at intervals longer than 7 years only if operators can 

adequately demonstrate that corrosion will not become a threat within the 

chosen time intervals. Otherwise, the reassessment must occur more 

frequently. As a safeguard to ensure that operators have identified threats 

facing these pipeline segments and have determined appropriate 

reassessment intervals, PHMSA and state regulatory agencies are already 

conducting integrity management inspections of operators. They plan to 

inspect most operators’ integrity management activities by 2009. 

The provision to increase the cap on pipeline safety grants to states appears 

reasonable given that states’ workloads are expanding, but funding sources 

and oversight of states’ expanded activities would need to be addressed in 

order to ensure that the increased grants are appropriately carried out. 

PHMSA has identified several potential funding sources, such as 

reprioritizing the agency’s budget and increasing pipeline user fees. For 

oversight, PHMSA anticipates integrating states’ expanded activities into the 

agency’s current oversight approach that relies on annual reports from states 

and field evaluations. 

www.gao.gov/cgi-bin/getrpt?GAO-06-1027T.

To view the full product, including the scope 

and methodology, click on the link above. 

For more information, contact Katherine 

Siggerud at (202) 512-2834 or 

siggerudk@gao.gov. 
Mr. Chairman and Members of the Subcommittee: 

We appreciate the opportunity to assist the Subcommittee in its efforts to 

reauthorize the Pipeline Safety Improvement Act of 2002, which 

strengthened federal pipeline safety programs and enforcement, state 

oversight of pipeline operators, and public education on pipeline safety. 

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

this Subcommittee and others on aspects of the integrity management 

program for gas transmission pipelines established under the 2002 act.1

 We

appeared before this subcommittee in April to discuss these topics.2

 This 

statement focuses on three areas that are related to the Subcommittee’s 

July 20, 2006, draft bill; H.R. 5782, as introduced; and the administration’s 

pipeline reauthorization, introduced as H.R. 5678. These three areas are

(1) an overall assessment of the integrity management program, (2) the 7-

year reassessment requirement, and (3) provisions to increase state 

pipeline safety grants. 

Our work is based on our review of laws, regulations, pipeline 

performance data, and other guidance from the federal regulator—the 

Pipeline and Hazardous Materials Safety Administration (PHMSA)—as 

well as discussions with a broad range of stakeholders, including industry 

trade associations, pipeline safety advocate groups, state pipeline 

agencies, pipeline inspection contractors, and consensus standards 

organizations.

3

 We also reviewed industry consensus standards for 

maximum reassessment intervals developed by the American Society of

Mechanical Engineers. In addition, we surveyed the 47 state pipeline 

agencies responsible for inspecting intrastate gas transmission pipeline 

operators on their plans for conducting inspections of operators’ integrity 

 1

Under integrity management, operators are required to develop programs to systematically

assess and mitigate safety threats, such as leaks or ruptures, for the portions of their 

pipelines that are in highly populated or frequently used areas (such as parks). They must

complete baseline assessments by 2012 and then reassess these pipeline segments every 7

years. Under PHMSA’s regulations, operators must reassess their pipelines for corrosion at

least every 7 years and for all time-dependent safety threats at least every 10, 15, or 20 

years. Transmission pipelines transport gas products from sources to communities and are 

primarily interstate. 

2

GAO, Gas Pipeline Safety: Preliminary Observations on the Implementation of the 

Integrity Management Program, GAO-06-588T (Washington, D.C.: April 27, 2006).

3

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

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

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

Page 1 GAO-06-1027T 
management programs.4 We also contacted 52 pipeline operators. These 

operators represent nearly 60 percent of the miles of pipeline assessed to 

date. We relied on pipeline operators’ professional judgment in reporting 

on the conditions that they found during their assessments of safety 

threats. Because we used a non-probability method of selecting these 

operators, we cannot project our findings nationwide.5

 As part of our 

work, we assessed the internal controls and the reliability of the data 

elements needed for this engagement, and we determined that the data

elements were sufficiently reliable for our purposes. We performed our 

work in accordance with generally accepted government auditing 

standards from August 2005 to July 2006. 

In summary: 

• While the gas integrity management program is still being implemented, 

early indications show that the program benefits pipeline safety, as 

intended by Congress. First, the condition of transmission pipelines is 

improving as operators complete their first round of pipeline assessments 

and make repairs. For example, 33 percent of the identified pipelines in 

highly populated or frequently used areas had been assessed and over 

2,300 repairs had been completed as of December 31, 2005 (latest data 

available). In addition, we estimate that up to 68 percent of the population 

that lives close to natural gas transmission pipelines is located in highly 

populated areas and is expected to receive additional protection as a 

result of improved pipeline safety as operators complete their baseline 

assessments by December 2012, as required. Furthermore, despite some 

uncertainty on the part of operators over the program’s documentation 

requirements, operators, gas pipeline industry representatives, state 

pipeline officials, and safety advocate representatives all agree that the

program enhances public safety, citing operators’ improved knowledge of

the threats to their pipeline systems that stems from systematic 

assessments as the primary benefit of the program. 

• Regarding the 7-year reassessment requirement, the draft Subcommittee 

bill would require the Secretary of Transportation to submit a legislative 

 4

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

agency. 

5

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

population because, in a nonprobability sample, some elements of the population being

studied have no chance or have an unknown chance of being selected as part of the 

sample. 

Page 2 GAO-06-1027T 
proposal after it receives our report on the subject. Our work, which is 

nearing completion, concludes that periodic reassessments are beneficial, 

but that the 7-year reassessment requirement appears to be conservative

based on a number of factors. Among these are results of the baseline 

assessments conducted to date and the overall safety record of the gas 

transmission industry. In this regard, through December 2005, 76 percent 

of the operators (182 of 241) reporting baseline assessment activity

reported to PHMSA that their pipelines were in good condition and free of

major defects, requiring only minor repairs. Most of the 340 problems 

found were concentrated in just 7 pipelines, although it is not known how 

many of these problems were due to corrosion. (These assessments 

reported by the 241 operators covered about 6,700 miles, or about onethird of the nationwide total to be assessed by 2012.) These results are 

encouraging, since operators are required to assess their riskiest segments 

first. Furthermore, since operators are required to repair these pipelines, 

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

before reassessments begin toward the end of the decade. Regarding 

safety, PHMSA data show corrosion incidents are relatively rare: over the

past 5-1/2 years (from January 2001 through early July 2006), there were 26

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

year, on average—none of which resulted in death or injury.6

• The administration’s proposal would require the Secretary of 

Transportation to issue regulations basing reassessment intervals on 

technical data, risk factors, and engineering analyses. Based on our nearly

completed work, we think that this approach is reasonable and would 

achieve the safety objectives of the 2002 act. It is also consistent with the 

overall philosophy of the integrity management legislation passed by the 

Congress in 2002. As discussed later in this statement, if PHMSA 

incorporates existing industry consensus standards for corrosion into its 

regulations, operators would be allowed to reassess their pipelines for 

time-dependent threats at least every 10, 15, or 20 years only if the 

operator can adequately demonstrate that corrosion will not become a 

threat within the chosen time interval. If not, then the reassessment must

occur more frequently, perhaps at 7 or even fewer years. As a safeguard 

for ensuring that operators have identified threats facing pipeline 

segments and have determined appropriate reassessment intervals, 

PHMSA and state regulatory agencies are already conducting inspections. 

They plan to inspect most operators’ integrity management activities by 

2009. 

 6

There have been two corrosion-related incidents in the last 10-1/2 years that have resulted 

in a death or injury. Neither occurred in a highly populated or frequently used area. 

Page 3 GAO-06-1027T 
• The provision in the Subcommittee’s draft bill to increase the cap on 

pipeline safety grants to states from 50 percent to 80 percent of the cost of 

their expanded pipeline safety programs appears reasonable given that 

states’ workload is increasing to, among other activities, enforce integrity 

management requirements and damage prevention programs. However, if 

Congress approves this provision, two areas would need to be addressed 

to ensure that the increased grants are appropriately carried out: the 

source of funding for the increased grant amounts and oversight of the 

expanded state pipeline safety activities. According to PHMSA, the agency

has identified funding options—including reprioritizing the agency’s 

budget to channel funds from other activities (such as research) and 

increasing user fees charged to pipeline companies —but has not 

developed a specific plan for how to provide additional funds to states. 

PHMSA currently oversees state pipeline safety activities through annual 

reports from the states and field evaluations. According to PHMSA 

officials, expanded state pipeline safety agency activities would be 

included in PHMSA’s oversight approach. 

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

pipelines that are owned and operated by approximately 900 operators. 

These pipelines are important to the nation because they transport nearly 

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

energy supply. Gas transmission pipelines typically move gas products 

over long distances from sources to communities and are primarily 

interstate. They generally deliver natural gas to local distribution pipelines, 

which distribute the gas to commercial and residential end-users. Local 

distribution companies may also operate small portions of transmission 

pipelines. 

PHMSA administers the national regulatory program to ensure the safe 

transportation of natural gas and hazardous liquid by pipeline. In general,

PHMSA retains full responsibility for inspecting and enforcing regulations 

on interstate pipelines, but it has arrangements with 48 states, the District 

of Columbia, and Puerto Rico to assist with overseeing intrastate 

pipelines. These states are currently authorized to receive reimbursement 

of up to 50 percent of the costs of their pipeline safety programs from

PHMSA. 

Traditionally, PHMSA has carried out its oversight role using minimum 

safety standards that were uniformly applied to all pipelines based on the 

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

factors such as population within 660 feet of the pipeline—determines the 

Background 

Page 4 GAO-06-1027T 
applicable standards such as the thickness of the pipe required and the 

pressure at which it can operate. The Pipeline Safety Improvement Act of 

2002 modified PHMSA’s traditional oversight approach by supplementing 

the minimum standards with a risk-based program for gas transmission 

pipelines. This program—termed “integrity management”—requires gas 

transmission pipeline operators to assess and mitigate safety threats, such 

as leaks or ruptures due to incorrect operation or corrosion, to pipeline 

segments that are located in highly populated or frequently used areas, 

such as parks. Specifically, operators are required to perform baseline 

assessments on half of the pipeline mileage located in these areas by 

December 2007, and the remainder by December 2012. Those pipeline 

segments potentially facing the greatest risks of failure from leaks or 

ruptures are to be assessed first. As of December 2005 (latest data 

available), 447 gas pipeline operators reported to PHMSA that about 

20,000 miles of their pipelines (about 7 percent of all gas transmission 

pipeline miles) lie in highly populated or frequently used areas. Individual

operators reported that they have as many as about 1,600 miles and as few 

as 0.02 miles of pipeline in these areas. 

The 2002 act also requires that operators reassess these pipeline segments 

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

act, PHMSA requires that operators reassess these pipeline segments for 

corrosion damage at least every 7 years in its implementing regulations, 

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

over time.7

 (See fig. 1.) PHMSA’s regulations also incorporated, as 

mandatory, voluntary industry consensus standards on maximum 

reassessment intervals into these regulations for other types of safety 

threats. The industry standards require that operators reassess gas 

pipelines at least every 10, 15, or 20 years for all safety threats depending

primarily on the condition of the pipelines and the pressure under which 

they operate. If conditions warrant, reassessments must occur more 

frequently. In addition, operators must perform prevention and mitigation 

activities—such as monitoring their pipelines for excavation or corrosion 

damage—on a continuing basis. 

 7

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

movement, or incorrect operation. 

Page 5 GAO-06-1027T 
Figure 1: Reassessments Every 7 Years for Corrosion Supplement Broader Periodic 

Reassessments 

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

reassessments are supposed to occur more frequently if conditions warrant. 

Operators are making good progress in assessing and repairing their 

pipelines, thereby improving the safety of their pipeline systems. As of 

December 2005, operators had assessed about 6,700 miles of their 20,000 

miles—or about 33 percent—of pipelines located in highly populated or 

frequently used areas. This progress indicates that they are well on their 

way to meeting the requirement to conduct baseline assessments on 50 

percent of their pipelines in these areas by December 2007. In addition to

assessing their pipelines, operators are also making progress in fulfilling 

the requirement to repair problems found on their pipelines in highly 

populated or frequently used areas. In the 2 years that operators have 

reported the results of integrity management, they have completed 340 

repairs that were immediately required and another 1,981 scheduled 

repairs in highly populated or frequently used areas.8

 While it is not 

possible to determine how many of these needed repairs would have been

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

routinely assess pipelines enables operators to identify problems that may 

otherwise go undetected. Furthermore, the benefits of integrity 

management expand beyond highly populated or frequently used areas 

because a large number of operators are using internal inspection tools to

assess their pipelines. These tools must be inserted and removed from the 

Gas Integrity 

Management Program 

Benefits Pipeline 

Safety 

 8

A repair must be made immediately when specific conditions are identified related to the 

strength of a pipeline such as, a dent with an indication of metal loss or cracking, or an 

anomaly judged to require immediate action. Scheduled repairs must be made within 1 year 

and generally include conditions where a dent has been identified but there is no indication 

of metal loss. 

Page 6 GAO-06-1027T 
pipelines at designated locations that often run through other areas. 

Consequently, operators reported having assessed about 44,000 miles of 

pipelines located outside highly populated or frequently used areas, 

representing about 15 percent of all gas transmission pipelines. While 

operators are not required to report to PHMSA the results of these 

expanded assessments, operators we spoke with said that they plan to 

make necessary repairs identified through the assessments regardless of 

where they are identified. 

We estimate that the integrity management program should offer 

additional safety benefits over the minimum safety standards for up to 68 

percent of the population living close to gas transmission pipelines. This 

estimate corresponds with PHMSA’s estimate of two-thirds of the 

population. 

A number of representatives from pipeline industry organizations, state 

pipeline agencies, safety advocate groups, and operators that we 

contacted agree that integrity management benefits public safety because

it requires all operators to systematically assess their pipelines to gain a 

comprehensive knowledge about the risks to their pipeline systems. Other 

benefits cited by operators include improved communications within their 

companies and more strategic resource allocation. 

While the operators we contacted generally believe integrity management 

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

of the operators we spoke with said that they have hired additional staff or 

contractors as a result of the integrity management requirements. In 

addition, 19 of the operators we contacted (37 percent) were concerned 

about the level of documentation needed to support their gas integrity 

management programs. PHMSA requires operators to develop an integrity 

management program and provides a broad framework for the elements

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

the flexibility to develop their programs to best suit their companies’ 

needs, but each operator must develop and document specific policies and 

procedures to demonstrate its commitment to compliance with and 

implementation of the integrity management program. Operators may use 

existing policies and procedures if they meet the requirements of integrity

management. In addition, an operator must document any decisions made 

related to integrity management to demonstrate that it understands the 

threats to their pipelines and is systematically managing their pipelines for 

these threats. While the operators we contacted generally agreed with the 

need to document their policies and procedures, some said that the 

detailed documentation required for every decision is very time consuming 

Page 7 GAO-06-1027T 
and does not contribute to the safety of pipeline operations. In addition, a 

few operators expressed concern that they will not know if they have 

sufficient documentation until their programs have been inspected. Initial

inspections of operators by PHMSA and state pipeline agencies have 

confirmed that some operators are experiencing difficulty with 

documentation but are generally doing well with assessments and repairs. 

According to PHMSA and state officials, as operators continue to develop

and implement their integrity management programs and as they are 

provided feedback during inspections, the documentation issues identified 

during these initial inspections should be resolved. 

Another concern raised by 33 (65 percent) of the operators is the 

requirement to reassess their pipelines for corrosion problems at least 

every 7 years. This issue is discussed in the following section.

Periodic reassessments of pipeline threats are beneficial because threats—

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

over time. However, the findings from baseline assessments conducted to

date and the generally safe condition of gas transmission pipelines leads 

us to conclude that the 7-year requirement appears to be conservative.

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

operators (182 of 241) reporting baseline assessment activity to PHMSA 

told the agency that their pipelines were in good condition, free of major 

defects, and requiring only minor repairs.9

 (See fig. 2.) The remaining 59

operators found 340 problems requiring immediate repairs. About 60 

percent of these problems occurred in seven operators’ pipelines. Since 

PHMSA does not require that operators tell it the nature of the problems 

found, we do not know how many, if any, were due to corrosion. These 

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

nationwide total to be assessed.10

The 7-year 

Reassessment 

Requirement Appears 

to be Conservative 

 9

We contacted 52 operators about the results of their baseline assessments, and the results 

were largely consistent with the overall data reported to PHMSA. 

10Another way to assess progress in completing baseline assessments and the effect of

problems found would be to measure gas flows or pipeline capacity in those areas. This 

information is not readily available. 

Page 8 GAO-06-1027T 
Figure 2: Most Operators Reported That Their Pipelines Are In Good Condition, as 

of December 2005 

Source: GAO presentation of PHMSA data. 

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

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

49 miles), 41 operate mid-sized pipeline systems (50-199 miles), and 59 operate larger pipeline 

systems (200 or more miles). 

It is encouraging that the majority of operators nationwide reported that 

they found few or no problems requiring immediate repairs, because 

operators are supposed to assess pipeline segments facing the greatest 

risk of failure from leaks or ruptures first, as required by the 2002 act. In 

addition, since operators are required to identify and repair significant 

problems, the overall safety and condition of the pipeline system should 

be enhanced before reassessments begin toward the end of the decade. 

Regarding the industry’s overall safety record, over the past 5-1/2 years 

(from January 2001 through early July 2006), there were 143 corrosionrelated incidents over the 295,000-mile transmission system (26 per year, 

on average)—none of which resulted in death or injury. Over the past 10-

1/2 years, 12 people have died and 3 have been injured in two corrosionrelated incidents.11 Neither of these incidents occurred in a highly 

populated or frequently used area. 

About 80 percent of the 52 operators that we contacted prefer that 

reassessment intervals be based on the condition and characteristics of 

 11All the fatalities and all but one of the injuries occurred in one incident. Over the same 

period, an average of 3 people have died and 8 people have been injured per year from all 

causes of natural gas transmission pipeline incidents.

Page 9 GAO-06-1027T 
the pipeline segment rather than on a prescriptive standard. About half of

these operators (28) expressed a preference for the industry consensus 

standard developed by the American Society of Mechanical Engineers 

(ASME B31.8S-2004) for setting reassessment intervals for time-dependent

threats because it incorporates a risk-based approach (for pipeline failure) 

and is based on science and engineering knowledge. This standard sets 

reassessment intervals at a maximum of 10 years for high-stress pipeline 

segments, 15 years for medium-stress segments, and 20 years for lowstress segments.12 Maximum reassessment intervals, such as those in the 

industry consensus standard, incorporate such risk concepts as built-in 

safety factors (e.g., wall stress, test pressure, or predicted failure), 

conditions, and potential consequences of a pipeline incident on a 

segment-by-segment basis. The maximum intervals of 10, 15, and 20 years 

are based on worst-case corrosion growth rates. 

Industry consensus standards allow for maximum reassessment intervals

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

adequately demonstrate that corrosion will not become a threat within the 

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

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

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

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

rupture. 

The industry consensus standards were developed in 2001 and updated in

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

engineers, contractors, operators, local distribution companies, and 

pipeline manufacturers; more than 20 technical studies conducted by the 

Gas Technology Institute, ranging from pipeline design factors to natural 

gas pipeline risk management; and other industry consensus standards 

including the National Association of Corrosion Engineers standards, on 

topics such as corrosion. Contributors have been practicing aspects of 

risk-based assessments successfully for over 10 years. The ASME standard 

serves as a foundation for nearly every section of PHMSA’s integrity 

management regulations. The ASME standard was reviewed by the 

American National Standards Institute.13 The Institute found that the 

 12Stress is measured in terms of operating pressure in relation to wall strength.

13The American National Standards Institute is a private, non-profit organization whose

mission is to promote and facilitate voluntary consensus standards and promote their 

integrity. The Institute does not approve the technical merits of proposed national 

standards. 

Page 10 GAO-06-1027T 
standard was developed in an environment of openness, balance, 

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

National Standard. 

While the mechanical engineering standards are voluntary for the industry, 

PHMSA incorporated them as mandatory in its gas transmission integrity 

management regulations. The mechanical engineering society’s standard 

for setting reassessment intervals is not the only industry consensus 

standard in PHMSA’s integrity management regulations. The regulations 

incorporate other industry consensus standards for assessing corrosion 

threats and for determining temporary reductions in operating pressure. 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. The Office of 

Management and Budget’s Circular A-119 provides guidance to federal 

agencies on the use of voluntary consensus standards, including the 

attributes that define such standards. 

Of the 52 operators we contacted, 44 had undertaken baseline 

assessments, and 23 of these have calculated their own reassessment 

intervals.14 Twenty of these 23 operators indicated that, based on the 

conditions they identified during their baseline assessments, they would 

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

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

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

they would reassess their pipelines at intervals shorter than the industry 

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

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

requirement appears to be conservative for most pipelines. 

PHMSA and the state pipeline agencies plan to inspect all operators’ 

compliance with integrity management reassessment requirements, among 

other things, to ensure that operators continually and appropriately assess 

the conditions of their pipeline segments in highly populated or frequently 

used areas. These inspections should serve as a check as to whether 

Safeguards Exist if an 

Alternative Standard for 

Corrosion Reassessments 

is Allowed 

 14The other 21 operators either (1) have not yet calculated reassessment intervals; (2) do 

not intend to, given prescriptive federal (7 years) or state (5 years in Texas) reassessment 

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

Page 11 GAO-06-1027T 
operators have identified threats facing these pipeline segments and 

determined appropriate reassessment intervals. PHMSA and states have

begun inspections and expect to complete most of the first round of 

inspections no later than 2009. As of June 2006, PHMSA has completed 20

of about 100 inspections and, as of January 2006, states have begun or 

completed about 117 of about 670 inspections. Initial results from these 

inspections show that operators are doing well in assessing their pipelines 

and making repairs, but, as discussed earlier, some need to better 

document their programs. Based on the initial inspection results to date, 

PHMSA and states did not find many issues that warranted enforcement 

actions. 

Finally, it is important to note that, in addition to periodic reassessments, 

operators must perform prevention and mitigation activities on a 

continuing basis. PHMSA regulations require that all operators of 

pipelines, including those outside highly populated or frequently used 

areas, patrol their pipelines for excavation and other damage, survey for 

leakage, maintain valves, ensure that corrosion-preventing protections are 

working properly, and take other prevention and mitigation measures. 

(Attachment I summarizes results of our work to date on the expected 

availability of resources for pipeline reassessments and the likely impact 

of assessment activity (including reassessments) on the nation’s natural 

gas supply. We will discuss these topics in more detail in when we report 

on the 7-year reassessment requirement this fall.) 

The Subcommittee’s draft bill proposes to increase the matching funds 

that PHMSA provides to states for pipeline safety program activities from 

a maximum of 50 percent to a maximum of 80 percent of a state’s pipeline

safety program costs. The increased funding would offset states’ increased 

workload, such as activities related to gas transmission integrity 

management and other provisions in the 2002 act. All three legislative

proposals also contain provisions, such as damage prevention programs, 

that could increase states’ workloads. Furthermore, state pipeline safety

activities would increase if PHMSA implements its planned integrity 

management program for distribution pipelines. Our recent survey to state 

pipeline safety agencies about their integrity management oversight 

programs showed that 39 of 47 state agencies are experiencing challenges

in staffing, which could require increased funding. For example, two state 

officials told us that state agencies are losing trained inspectors because 

the state salaries are typically lower than what operators pay. PHMSA 

Increasing State 

Funding Appears 

Reasonable, but 

Funding Sources and 

Oversight Plans

Would Need To Be 

Addressed 

Page 12 GAO-06-1027T 
proposes to implement the increased funding in 5 percent increments over 

a 6-year period starting in fiscal year 2008. 

We believe that the proposed increase in state grants to offset expanded

state activities appears reasonable, provided that appropriate funding 

sources are identified and that the activities are included in PHMSA’s 

oversight of state pipeline safety programs. According to PHMSA, the 

agency has several options for increasing funding for state grants, but has 

not developed a specific plan for how to provide additional funds. One 

option is for PHMSA to reprioritize its budget to channel additional funds 

from other activities, such as research, to states. Another option may be to

increase user fees that are charged to pipeline companies. User fee 

assessments in fiscal year 2006 were about $150 per pipeline mile for 

natural gas transmission operators and about $76 per pipeline mile for 

hazardous liquid pipelines. All of these options involve tradeoffs among 

PHMSA’s pipeline safety oversight activities or could result in increased 

fees from the pipeline industry. Therefore, the effects of these options 

would need to be carefully analyzed in order to find a balanced solution. 

According to PHMSA, the agency plans to monitor increased state pipeline 

safety activities through its current oversight approach, which consists of 

reviewing annual reports from states and field evaluations of state 

activities. States are required to submit documentation annually about

their pipeline safety program activities for the previous year, including 

information on the state’s pipeline operators, inspections conducted, and 

enforcement of pipeline regulations. States are also required to submit a 

description of all ongoing and planned activities and an estimate of the 

total expenses for the next calendar year. PHMSA validates the 

information submitted by each state and attends at least one state 

inspection during field evaluations. As state pipeline safety activities 

expand, PHMSA would need to determine the best approach for including

the new activities in its oversight of state pipeline safety programs. 

The overall integrity management framework laid out in the Pipeline 

Safety Improvement Act is improving the safety of gas transmission 

pipelines. We have not identified issues that bring into question the basic 

framework of integrity management. Overall, we believe that PHMSA has 

done a good job in implementing the act. While we expect to make several 

recommendations to PHMSA when we complete our work, they will be 

aimed at incremental improvements, rather than major restructuring. 

Finally, regarding the 7-year reassessment requirement, our preliminary 

view is that these reassessment intervals should be based on technical 

Concluding 

Observations 

Page 13 GAO-06-1027T 
data, risk factors, and engineering analyses rather than a prescribed term. 

We expect to make a recommendation to the Congress that the 2002 act be 

amended along these lines when we report on this issue. We expect to 

report to this Subcommittee and to other committees both on PHMSA’s 

implementation of integrity management and the 7-year reassessment 

requirement in September. 

For further information on this statement, please contact Katherine 

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

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

Dykes, Maria Edelstein, Heather Frevert, Bert Japikse, Timothy Guinane, 

Matthew LaTour, James Ratzenberger, and Sara Vermillion. 

GAO Contact and 

Staff 

Acknowledgements 

Page 14 GAO-06-1027T 
Page 15 GAO-06-1027T 

Appendix: Availability of Resources to 

Conduct Reassessments and Possible 

Impacts on the Nation’s Natural Gas Supply 

This appendix summarizes results of our work to date on the expected 

availability of resources for pipeline reassessments and the likely impact 

of assessment activity (including reassessments) on the nation’s natural 

gas supply. 

Sufficient resources may be available for operators to reassess their 

pipelines, but some uncertainty exists. Thirty-seven of the 52 operators, an

in-line inspection association and four inspection contractors that we 

contacted told us that services and tools needed to conduct assessments 

will likely be available for baseline assessments and they do not anticipate

difficulties obtaining these resources in the future. Operators that reported 

both baseline and reassessment schedules told us they plan to reassess 42 

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

using in-line inspection.1

 An in-line inspection association and two 

contractors we contacted said that the in-line inspection industry is well 

established and has the capacity to expand readily. Operators plan to use 

direct assessment or confirmatory direct assessment methods in 

reassessing another 54 percent of their pipeline miles.2

 However, they told 

us that expertise for direct assessment methods is limited; therefore, they 

may not be as readily available to all operators. 

The Interstate Natural Gas Association of America (INGAA), the American 

Gas Association (AGA) and we asked operators to estimate the number of 

miles of pipeline they planned to assess through 2012 in order to 

determine whether an increase in overall assessment activity would occur 

because of the overlap between completing baseline assessments and 

beginning reassessments from 2010 through 2012. The results were 

conflicting: the industry effort showed an increase in activity, while ours 

showed a decrease. (See fig. 3.) The reasons for these contrasting findings

are unclear but may be due, in part, to the difference in methods used in 

collecting this information. 

Sufficient Resources May 

Be Available for Pipeline 

Reassessments 

 1

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

record anomalies, such as metal loss and damage. 

2

Direct assessment and confirmatory direct assessment involve using above-ground 

detection instruments, and then excavating suspected problem areas. 
Figure 3: GAO and INGAA/AGA Results Show Different Trends in their Required Assessment Activity During the Overlap 

Period

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

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

Miles of pipeline

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

Year 

GAO 

INGAA/AGA 

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

INGAA analyzed the possible impact of requiring assessments and periodic 

reassessments and found that significant disruptions in the natural gas 

supply and considerable price increases could occur.3

 A more moderate 

impact was predicted in three subsequent analyses—two reviews of the 

INGAA study performed for PHMSA by the John A. Volpe National 

Transportation Systems Center and by the Department of Energy during 

the congressional debate over the pipeline bill, and a post-act PHMSA 

Impact of Periodic 

Reassessments on 

Natural Gas Supply 

May be Less than 

Foreseen 

 3

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

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

Page 16 GAO-06-1027T 
evaluation of its implementing regulations.4

 A waiver provision was 

included in the 2002 act after INGAA’s study was completed; this may 

serve as a safety valve if it appears that the natural gas supply may be 

disrupted. Finally, of the 44 natural gas pipeline operators that we 

contacted that had begun baseline assessments,5

 26 operators (59 percent) 

indicated that their assessments and repairs did not require them to 

shutdown their pipelines or reduce their operating pressure. Sixteen (36 

percent) reported minor disruptions in their gas supply because they 

temporarily shut down pipelines and reduced operating pressure to 

conduct assessments or repairs. They told us that they used alternate gas 

sources, such as liquefied natural gas, to sustain their customers’ gas 

supply. The remaining two operators told us that they were not able to 

meet all their customers’ needs, but the customers were able to obtain 

natural gas from other sources. 

 4

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

Pipeline Integrity Management in High Consequence Areas (Gas Transmission 

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

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

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

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

Final Regulatory Evaluation, Pipeline Integrity Management in High Consequence 

Areas (Gas Transmission Pipelines), March 28, 2002. 

5

Fifty of the 52 operators that we contacted operate natural gas pipeline and six have not 

yet begun baseline assessment activities. 

Page 17 GAO-06-1027T (542099) 
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