United States Government Accountability Office

Washington, DC 20548

February 16, 2012

The Honorable John D. Rockefeller

Chairman

Committee on Commerce, Science, and Transportation

United States Senate

The Honorable Frank Lautenberg

Chairman

Subcommittee on Surface Transportation and Merchant 

 Marine Infrastructure, Safety, and Security

Committee on Commerce, Science, and Transportation

United States Senate

Subject: Safety Effects of Less Prescriptive Requirements for Low-Stress Natural 

Gas Transmission Pipelines Are Uncertain

More than 2.6 million miles of pipelines form a nationwide network to transport the 

majority of natural gas consumed in the United States. This extensive gas pipeline 

network includes several different types of pipelines, including

• transmission pipelines, which transport product over long distances at high 

pressure from sources to communities; 

• distribution pipelines, which operate at lower pressures to deliver natural gas 

to homes and businesses; and 

• low-stress transmission pipelines, which typically connect transmission 

pipelines to distribution pipelines and may operate at pressures that are 

similar to the latter. 

The Pipeline and Hazardous Materials Safety Administration (PHMSA), within the 

Department of Transportation (DOT), is responsible for establishing safety 

requirements for these pipelines and has traditionally included low-stress 

transmission pipelines in its regulations for all transmission pipelines. In 2004, 

PHMSA implemented a risk-based regulatory approach called “integrity 

management” for natural gas transmission pipelines, including low-stress 
2 GAO-12 389R Low–Stress Pipeline Regulations

transmission pipelines.1 In 2010, PHMSA extended integrity management to 

distribution pipelines, but modified the requirements to account for differences in 

transmission and distribution pipelines, such as differences in pipeline size and 

operating pressure.2 Some stakeholders have suggested that the requirements for 

distribution pipelines should apply to low-stress transmission pipelines because of 

the similarity in operating pressures of these two types of pipelines. You asked that 

we consider the safety implications to the public of this proposal. Accordingly, this 

report focuses on how applying distribution integrity management requirements to 

low-stress gas transmission pipelines might affect the safety of these pipelines.

To perform our work, we reviewed and compared laws, regulations, and guidance 

from PHMSA. We also interviewed a broad range of stakeholders, including 

representatives of industry trade associations, pipeline safety advocacy groups, 

state pipeline agencies, and pipeline operators. In addition, we surveyed 52 officials 

from state pipeline safety agencies3 in 50 states and the District of Columbia—

achieving a 100 percent response rate—to collect information otherwise not 

available from PHMSA, including state officials’ views on changing safety 

requirements for low-stress transmission pipelines. We also analyzed technical 

documents examining the point at which pipelines leak or rupture, reports on the 

integrity management program and related progress, and pipeline accident reports. 

Furthermore, we visited state pipeline safety officials and pipeline operators and 

associations in Colorado, Texas, and Pennsylvania, where we interviewed officials 

and representatives to obtain firsthand information on pipeline safety issues—

including the potential effects of applying the new requirements for distribution 

pipelines to low-stress gas transmission pipelines—and examined pipeline 

infrastructure. We selected these sites as illustrative of differences in overall pipeline 

mileage, geography, and emerging pipeline issues.

We conducted this performance audit from February 2011 to January 2012 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.

Summary

Applying PHMSA’s new distribution integrity management requirements to lowstress transmission pipelines would result in less prescriptive safety requirements for 

these pipelines. Overall, requirements for distribution pipelines are less prescriptive 

than requirements for transmission pipelines in part because the former operate at 

 

1

49 C.F.R. § 192, Subpart O. 

2

49 C.F.R. § 192, Subpart P. 

3

Two state pipeline safety officials from separate agencies in Arkansas that are responsible for 

overseeing pipeline safety in that state responded to our survey.
Page 3 GAO-12 389R Low–Stress Pipeline Regulations

lower pressure and pose lower risks in general than the latter. For example, the 

integrity management regulations for transmission pipelines allow three types of indepth physical inspections.4 In contrast, distribution pipeline operators can 

customize their integrity management programs to the complexity of their systems, 

including using a broader range of methods for physical inspection. While PHMSA 

officials stated that “less prescriptive” does not necessarily mean less safe, they also 

stated that distribution integrity management requirements for distribution pipelines 

can be more difficult to enforce than integrity management requirements for 

transmission pipelines. Currently, PHMSA can grant special permits to modify 

requirements for individual pipelines, if merited,5 but applying the new distribution 

integrity management requirements to low-stress transmission pipelines would affect 

all such pipelines. 

If PHMSA’s requirements for low-stress transmission pipelines changed, operators 

whose systems consist almost entirely of distribution pipelines and include only a 

short low-stress transmission pipeline segment could benefit because they would be 

subject to one set of integrity management requirements instead of two. This might 

allow them to apply more resources to other safety priorities. However, the effect of 

such a change on pipeline safety is unclear. While the consequences of a low-stress 

transmission pipeline failure are generally not severe because these pipelines are 

more likely to leak gradually rather than rupture, the point at which a gas pipeline 

fails by rupture is uncertain and depends on a number of factors in addition to 

pressure. For example, the size or type of defect and the materials used to construct 

the pipeline also influence whether a pipeline leaks or ruptures. In addition, the 

mileage and location of pipelines that would be affected by such a regulatory change 

are currently unknown, although PHMSA recently changed its reporting 

requirements to collect such information. The concern is that because distribution 

pipelines are located in highly populated areas, the low-stress transmission pipelines 

that are connected to them could also be located in highly populated areas. Overall, 

officials we contacted from state pipeline safety agencies and PHMSA supported the 

current integrity management requirements for low-stress transmission pipelines. 

Specifically, about 58 percent of the officials from state pipeline safety agencies we 

surveyed (30 of 52), responded that the current requirements would best apply to 

low-stress transmission pipelines—affirming the current regulatory environment. By 

comparison, 10 of 52 officials were in favor of changing the regulatory environment 

by applying distribution integrity management requirements to low-stress 

transmission pipelines, and 12 of 52 officials stated no opinion on the issue. In light 

of the uncertain safety effects of changing safety requirements for low-stress 

transmission pipelines and the opinion of state pipeline safety officials we surveyed, 

the current regulatory approach of applying more prescriptive transmission pipeline 

requirements—with an option for operators to apply for a special permit—appears 

reasonable.

 

4

49 C.F.R. § 192.921. 

5

49 U.S.C. § 60118(c).
4 GAO-12 389R Low–Stress Pipeline Regulations

Background

A network of transmission and distribution pipelines covering more than 2.6 million 

miles transport the majority of natural gas consumed in the United States. Gas 

transmission pipelines typically move natural gas across state lines and over long 

distances, from sources to communities. These pipelines are typically 12 to 42 

inches in diameter and can generally operate at pressures up to 72 percent of 

specified minimum yield strength (SMYS).6 By contrast, local distribution pipelines 

generally operate within state boundaries to receive gas from transmission pipelines 

and distribute it to commercial and residential end users. Local distribution pipelines 

typically range from less than 0.5 to more than 24 inches in diameter and operate 

well below 20 percent of SMYS. Connecting the long-distance transmission pipelines 

to the local distribution pipelines are lower stress transmission pipelines that may 

transport natural gas for several miles at pressures between 20 and 30 percent of 

SMYS. 

The major causes and consequences of accidental releases of gas from pipelines 

differ for transmission and distribution pipelines. Corrosion—either internal or 

external—is one of the leading causes of releases from gas transmission pipelines. 

Given the high pressure of the gas as it is transported through these pipelines,

failures can lead to catastrophic ruptures, releasing high volumes of gas that can 

ignite and explode. For distribution pipelines, in contrast, damage from excavation 

and other outside forces is the major cause of accidental releases. Distribution 

pipeline failures are more likely to involve slow leaks with limited volume because 

the internal gas pressure is much lower than for transmission pipelines. Whatever 

the cause, however, leaks can lead to gas migrating to and accumulating in 

buildings, potentially igniting and causing a fire—which could result in injury or death 

to residents. Natural gas has traveled underground along migration pathways, such 

as sewer lines, finding an ignition source some distance from the location of the 

release. Therefore, monitoring pipeline integrity is important to prevent both leaks 

and ruptures. 

PHMSA administers a national regulatory program intended to ensure the safe 

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

has full responsibility for inspecting interstate pipelines and enforcing regulations 

pertaining to them,7 although some states are designated as “interstate agents” to 

assist PHMSA.8

 

6

Pipelines 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 SMYS. The 

SMYS 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 SMYS (49 CFR § 192.3). Some transmission pipelines operate 

under special permits that allow different maximum operating pressure that could exceed 72 percent 

of SMYS.

PHMSA also has arrangements with the 48 contiguous states, the 

7

49 U.S.C. § 60102.

8

49 U.S.C. § 60106. The nine interstate agents for natural gas are Arizona, Connecticut, Iowa, 

Michigan, Minnesota, New York, Ohio, Washington, and West Virginia.
Page 5 GAO-12 389R Low–Stress Pipeline Regulations

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

PHMSA and participating state pipeline safety offices oversee operators’ compliance 

with two types of safety requirements: minimum safety standards and a 

supplemental, risk-based integrity management program. The minimum safety 

standards generally cover the design, construction, testing, inspection, operation, 

and maintenance of all pipelines, but generally do not account for differences in the 

kinds of threats and the degrees of risk that individual pipelines face. By contrast, 

PHMSA’s integrity management program requires operators to periodically9 assess 

their pipelines to identify threats and mitigate risks to pipeline segments in areas 

where the consequences of a pipeline failure would be most severe, such as 

populated areas.

The Pipeline Safety Improvement Act of 200210 required the Secretary of DOT to 

prescribe standards for gas transmission pipeline operators to implement integrity 

management plans, which led to the implementation of PHMSA’s integrity 

management program for transmission pipelines in 2004.11 Pursuant to the 2002 act, 

all gas transmission pipeline operators must periodically assess for and mitigate 

safety threats, such as corrosion. Integrity management requirements for 

transmission pipelines focus on portions of the pipeline located in highly populated 

or frequently used areas, like residential areas or parks, where significant 

consequences could result if an incident occurs. Such areas are referred to 

collectively as high-consequence areas.

12 Because the majority of transmission 

pipelines often traverse rural areas, including areas that are sparsely populated or 

where consequences would be low, the percentage of natural gas transmission 

pipeline mileage that is subject to integrity management requirements is small, about 

7 percent. PHMSA also established provisions within transmission integrity 

management for low-stress transmission pipelines, in recognition that these 

pipelines are more likely to fail by leak rather than by rupture compared to higher 

pressure transmission pipelines and thus pose a reduced risk to the public. For 

example, an operator could conduct an electrical survey to address the threat of 

external corrosion, instead of utilizing the full external corrosion direct assessment 

process. 

The Pipeline Inspection, Protection, Enforcement, and Safety Act of 200613

 

mandated that PHMSA also establish minimum standards for integrity management 

9

For example, operators are required to reassess their pipelines in high-consequence areas for 

corrosion problems at least every 7 years and for all safety threats at least every 10, 15, or 20 years, 

depending on the condition of the pipelines and the stress under which the pipeline segments are 

operated. 49 C.F.R. § 192.939.

10Pub. L. No. 107-355, § 14, 116 Stat. 2985, 3002 (Dec. 17, 2002).

1149 C.F.R. § part 192, subpart O.

1249 C.F.R. § 192.905. 

13Pub. L. No. 109-468, § 9, 120 Stat. 3486 (2006).
6 GAO-12 389R Low–Stress Pipeline Regulations

programs for distribution pipelines; PHMSA published these standards in a final rule 

in December 2009.14 These integrity management programs are similar to those 

required for gas transmission pipelines, but tailored to reflect the differences in 

distribution pipelines. For example, all distribution pipelines are considered to be in 

high-consequence areas because they are largely located in populated areas. As a 

result, distribution integrity management requirements apply to all distribution 

pipelines. The rule took effect February 2, 2010, and gas distribution operators were 

required to implement an integrity management program no later than August 2, 

2011.15 

Commenters on the distribution integrity management final rule in 2009 suggested 

that distribution operators that also operate low-stress gas transmission pipelines 

should be able to use distribution integrity management requirements for those 

transmission pipelines, rather than implement a separate integrity management 

plan.16 Commenters suggested that this could be done by amending the distribution

integrity management rule or by changing the definition of a transmission pipeline, 

but recognized that additional rulemaking might be needed as a result. In the final 

rule, PHMSA noted that stakeholder groups that studied the appropriateness of such 

a change concluded that additional technical work would be needed to support it. 

Specifically, they said a better understanding of the threshold between leakage and 

rupture was needed to determine if low-stress transmission pipelines should be 

regulated under a distribution integrity management program. PHMSA concluded 

that it might be appropriate to consider the change at a later date, and agreed with 

the need for additional technical work to inform any decision.

Less Prescriptive Requirements for Low-Stress Transmission Pipelines Could 

Benefit Some Operators, but Safety Effects Are Unknown

Changing Safety Requirements Would Result in Less Prescriptive Regulations for 

Low-Stress Gas Transmission Pipelines

Overall, integrity management—and most other—pipeline safety requirements are 

less prescriptive for distribution pipelines than for transmission pipelines. PHMSA’s 

integrity management requirement for assessments of gas transmission pipelines 

illustrates the prescriptive nature of the safety requirements for transmission 

pipelines. This requirement directs operators to perform an integrity assessment 

(physical inspection) of their transmission pipelines using a specific method17

 

1449 C.F.R. part 192, subpart P.

—in1549 C.F.R. § 192.1005. 

1674 Fed. Reg. 63934 (December 4, 2009). Comment topic 8.

1749 C.F.R. § 192.921.In general, the maximum reassessment interval allowable is seven years (49 

C.F.R. § 192.939). 
Page 7 GAO-12 389R Low–Stress Pipeline Regulations

line inspection,18 hydrostatic pressure testing,19 or direct assessment.20 Both in-line 

inspection and hydrostatic testing involve tools or techniques applied inside the 

pipeline, while direct assessment tools and techniques are applied externally. These 

assessment methods allow operators to detect specific anomalies21 in the pipeline, 

such as imperfections in the pipe wall or weld, that could lead to failure. (See fig. 1 

for an example of the equipment used for hydrostatic testing and fig. 2 for an 

example of the equipment involved in in-line inspections.)

Figure 1: Hydrostatic Testing Equipment Used to Test Pipeline Integrity

 

18In-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. In-line inspection allows 

operators to determine the nature of any problems without either shutting down the pipeline for 

extended periods or damaging the pipeline. In-line inspection devices can be run only from facilities 

established for launching and retrieving them. 

19Hydrostatic pressure testing entails sealing off a portion of the pipeline, removing the gas product, 

filling the pipeline segment with water, and increasing the pressure of the water above the rated 

strength of the pipeline to test its integrity. If the pipeline leaks or ruptures, the pipeline is excavated 

to determine the cause of the failure. Operators must shut down pipelines to perform hydrostatic 

testing.

20Direct assessment is a nonintrusive, aboveground instrument inspection that uses two or more 

types of diagnostic tools, such as a closed interval survey—to assess the coating of covered pipelines 

for corrosion damage—at predetermined intervals along the pipeline. Once the data are analyzed, the 

operator excavates and inspects segments of the pipeline suspected to have safety threats.

21All pipelines have anomalies, most of which are nonproblematic, in that they will not grow or lead to 

pipeline failure over time. Integrity management inspections are designed specifically to identify and 

control anomalies that can possibly lead to failure.
8 GAO-12 389R Low–Stress Pipeline Regulations

Figure 2: Example of In-Line Inspection Equipment to Detect and Record Pipeline Anomalies

In developing integrity management requirements for distribution pipelines, PHMSA 

did not prescribe the same types of assessments as it did for its transmission 

pipelines, because the assessments would often not be practicable for distribution 

pipelines. For example:

• Distribution pipelines are typically too narrow in diameter to accommodate 

in-line inspection tools. 

• Approximately half of the distribution pipeline system is nonmetallic, 

meaning that internal inspection tools cannot be used.22 

• Hydrostatic testing and direct assessment are time consuming and can be 

risky and inconvenient for the public. During a hydrotest, pipelines must be 

shut down and gas deliveries must be stopped or curtailed for some time. 

• Hydrostatic testing and direct assessment can interfere with normal 

activities in the vicinity of the testing. In particular, direct assessment 

involves excavation and disturbs property and infrastructure, potentially 

including roads and other utilities, with which distribution pipelines may be 

integrated. 

PHMSA’s approach for distribution pipelines requires all operators to implement an 

integrity management program that sets high-level performance objectives with 

implementation guidelines. For example, PHMSA requires pipeline operators to 

develop an integrity management program incorporating certain elements—such as 

identifying risks, evaluating and ranking risks, and identifying measures to address 

 

22In-line inspection tools use magnets to detect disturbances in the magnetic field that are caused by 

defects in the pipe. As a result, this method would be ineffective with plastic pipe.
Page 9 GAO-12 389R Low–Stress Pipeline Regulations

risks. 23 Operators have the flexibility, however, to create a plan at their discretion as 

long as they demonstrate how it satisfies integrity management requirements, which 

could include a broad range of preventative or mitigative methods. For example, a 

distribution operator may conduct a guided wave pipeline assessment, which uses 

ultrasonic waves to scan and inspect the pipe. While PHMSA officials stated that 

“less prescriptive” does not necessarily mean less safe, they also stated that 

integrity management requirements for distribution pipelines can be more difficult to 

enforce than integrity management requirements for transmission pipelines. This is 

because transmission pipelines must meet a specific set of fixed requirements as 

opposed to the flexible program allowed under distribution integrity management.

Other regulatory requirements—not just integrity management regulations—are also 

generally less prescriptive for distribution pipelines than for transmission pipelines, 

because distribution pipelines operate at lower pressures and pose lower risks. 

Specifically, regulations for valve spacing, construction, patrolling, line markers, 

recordkeeping, and leak repairs are all less prescriptive for distribution pipelines. For 

example, operators must patrol distribution pipelines to observe surface conditions 

at least twice a calendar year in areas or on structures where physical movement or 

external loading could cause failure or leakage, but for transmission pipelines in the 

most densely populated (high-consequence) areas, operators must patrol at least 

four times per year. As a result, if low-stress transmission pipelines adopted 

distribution pipeline requirements, then low-stress transmission pipelines located in 

highly populated (high-consequence) areas would be subject to less frequent leak 

surveys and patrolling than other transmission pipelines.

As an alternative to changing the safety requirements for all low-stress transmission 

pipelines, PHMSA can currently issue special permits exempting operators from 

compliance with one or more regulations.24

 

23Distribution integrity management plans include seven key elements: (1) have an understanding of 

the system, including the conditions and factors important to assessing risks; (2) identify threats 

applicable to the system, including potential future threats; (3) assess risks and characterize the 

relative significance of applicable threats to the system; (4) identify and put in place appropriate riskcontrol practices to prevent and mitigate risks from applicable threats consistent with the significance 

of these threats; (5) develop and monitor performance measures to evaluate effectiveness of 

programs, periodically evaluate program effectiveness, and adjust programs, as needed, to assure 

effectiveness; (6) must reevaluate threats and risks, determine the appropriate period for conducting 

complete program evaluations at least every 5 years and (7) periodically report a select set of 

performance measures to jurisdictional authorities. 49 C.F.R. Part 192, Subpart P.

The special permit process would allow 

PHMSA to evaluate the safety implications of the exemptions on a case-by-case 

basis, as opposed to applying less prescriptive requirements across the board for 

these types of pipelines. As of January 2012, PHMSA officials told us they have not 

received any requests for special permits to apply distribution integrity management 

requirements to low-stress transmission pipelines. 

2449 U.S.C. § 60118(c). 
10 GAO-12 389R Low–Stress Pipeline Regulations

Changing Requirements Could Benefit Some Operators, but Overall Effects on 

Safety Are Unknown

Changing the safety requirements for low-stress gas transmission pipelines could 

simplify compliance and create efficiencies for some pipeline operators, potentially 

allowing them to apply resources to other safety priorities. In 2006, we reported that 

according to operators, integrity management can be costly, when, for example, 

additional staff or contractors must be hired to implement integrity management 

requirements.25 Under the current regulations, some pipeline companies operating 

both distribution and low-stress transmission pipelines must address requirements 

for both distribution and transmission integrity management programs. While it is 

possible to have one integrity management plan that addresses both distribution and 

transmission integrity management requirements, some of these companies operate 

only a small segment of transmission pipeline that connects to an entire distribution 

pipeline network. For such companies, changing the safety requirements for lowstress transmission pipelines could create efficiencies because they would be 

subject to just one set of integrity management requirements. Furthermore, 

operators devote resources to comply with pipeline safety regulations, and these 

safety resources could be made available for other safety purposes. 

While changing the requirements for low-stress pipelines would benefit some 

operators, the impact on pipeline safety is unclear. For example, although low-stress 

gas transmission pipelines typically operate at pressures at which a pipeline failure 

will result in a leak, recent research has indicated that there is no definitive threshold 

at which a pipeline will leak as opposed to rupture, since pipeline integrity depends 

on a number of characteristics in addition to operating pressure. Though in general 

the threshold is in the range of 20 to 30 percent of SMYS—which is the typical 

operating pressure for low-stress transmission pipelines—the point at which a 

pipeline will rupture instead of leak varies depending on factors such as toughness, 

wall thickness, and the diameter of the pipe segment. For example, a 2011 study26

determined that the boundary could range from slightly below 20 percent of SMYS 

for pipelines with rarely used pipe materials to well over 30 percent of SMYS for 

many other pipelines with more robust materials. Furthermore, a 2001 study27

 

25GAO, 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).

determined that pipelines operating at less than 30 percent of SMYS are more likely 

to leak than to rupture, but noted that pipelines operating at lower pressure have 

also ruptured, because of a combination of factors such as the length of the defect 

and toughness of the pipe. According to one of the researchers of the study, 

26Gas Technology Institute, GTI, Leak-Rupture Boundary Determination Project, (Des Plaines, IL: 

December 2011). GTI completed a study funded by Operations Technology Development using 

incident and laboratory testing data with advanced modeling techniques to calculate the boundary 

between failure by leak and failure by rupture as a function of the pipe’s SMYS. 

27Gas Research Institute, Leak versus Rupture Considerations for Steel Low-Stress Pipelines, GRI00/0232, (Des Plaines, IL: January 2001). The report evaluated leak versus rupture as a function of 

wall stress, with a focus on natural gas pipelines operating through high-consequence areas.
Page 11 GAO-12 389R Low–Stress Pipeline Regulations

additional factors—such as damage incurred during installation and subsequent 

pressure increases around the damage—could increase the likelihood of an incident, 

even for lower pressure pipelines. In addition, some high-profile incidents have 

occurred on transmission pipelines operating at pressures slightly higher than 30 

percent of SMYS.28 For example, on September 9, 2010, a 30-inch-diameter 

underground natural gas transmission pipeline operating at 35 percent of SMYS in a 

residential area of San Bruno, California, suddenly ruptured. The resulting explosion 

and fire killed 8 people and destroyed 38 homes. 

Another reason why the effects of changing the safety requirements for low-stress 

transmission are unclear is that the mileage and location of pipelines that would be 

affected by such a change are currently unknown. The concern is that low-stress 

transmission pipelines subject to a change in safety requirements could be located 

in high-consequence areas. PHMSA did not collect this information in the past, 

although it recently revised its reporting requirements to do so. PHMSA’s 

transmission pipeline annual report form—revised in November 2010 for 2011 

reporting29—now requests information on the number of miles of pipeline and 

location by operating percentage of SMYS for each operator. Furthermore, of the 52 

officials from state pipeline safety agencies we surveyed, 31 responded that they do 

not track the location of the low-stress gas transmission pipelines in their state.30

However, by definition, low-stress transmission pipelines could be located in highconsequence areas because these pipelines connect to distribution pipeline 

networks. Therefore, a change in safety requirements could mean that low-stress 

gas transmission pipelines in high-consequence areas would now be subject to less 

prescriptive integrity management requirements. 

Overall, officials we contacted from state pipeline safety agencies and PHMSA 

supported the current integrity management requirements for low-stress 

transmission pipelines. For example, of the 52 officials from state pipeline safety 

agencies we surveyed, 30 responded that transmission pipeline integrity

management requirements would better apply to low-stress transmission pipelines—

affirming the current regulatory environment. By contrast, 10 of 52 officials from state 

pipeline safety agencies responded that distribution integrity management 

requirements would be better for these types of pipelines.31

 

28According to PHMSA, its database of significant incidents for gas transmission pipelines from 2010 

to January 2012 identified 27 incidents that occurred on pipelines operating at pressures greater than 

or equal to 30 percent of SMYS to less than 40 percent of SMYS at the time of the incident. Of the 27 

incidents, 3 were identified as the “rupture” release type occurring at percentages of SMYS close to 

30 percent.

Furthermore, according 

to some PHMSA officials, lower stress transmission pipelines should be subject to 

2949 C.F.R. §§ 191, 192, 193, and 195.

30Of the 52 officials from state pipeline safety agencies we surveyed, 18 responded that they do track 

the location of low-stress gas transmission pipelines, and another 3 officials responded that they did 

not know.

31Of the 52 officials from state pipeline safety agencies surveyed, 12 responded that they had no 

opinion on the matter.
12 GAO-12 389R Low–Stress Pipeline Regulations

more prescriptive requirements than would be applicable under the distribution

integrity management program because low-pressure leaks can still cause 

significant damage. 

Concluding Observations

Even though some pipeline operators might benefit from changing the regulations for 

low-stress transmission pipelines, the uncertain safety effects raise concerns about 

this change. In the current regulations, pipelines operating at below 20 percent of 

SMYS are subject to less prescriptive requirements, but a change could mean that 

pipelines operating at up to 30 percent of SMYS would also be subject to less 

prescriptive requirements. Given the lack of a definitive threshold at which pipelines 

that operate in this pressure range will rupture, not knowing the mileage and location 

of pipelines that would be affected by a change in requirements and not knowing the 

potential proximity of these pipelines to high-consequence areas makes such a 

change questionable. Furthermore, the majority of state pipeline safety officials 

responding to our survey support maintaining the current regulatory environment, 

which includes an option for operators to apply for a special permit if complying with 

requirements for two separate integrity management programs would be 

burdensome.

 

Agency Comments

We provided a draft of this correspondence to DOT officials for their review and 

comment. The officials provided technical corrections which we have incorporated 

throughout.

We are sending copies of this report to the Secretary of Transportation. The report is 

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

If you or your staff have any questions concerning this correspondence, 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 

correspondence. Major contributors to this correspondence were Sara Vermillion, 

Assistant Director; Adam Yu, Analyst-in-Charge; Aisha Cabrer; Matt Cail; Elizabeth 

Eisenstadt; Colin Fallon; David Hooper; and Rebecca Shea. 

Susan Fleming

Director, Physical Infrastructure Issues

(541087)
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