oversight

Safety Effects of Less Prescriptive Requirements for Low-Stress Natural Gas Transmission Pipelines Are Uncertain

Published by the Government Accountability Office on 2012-02-16.

Below is a raw (and likely hideous) rendition of the original report. (PDF)

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
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 agencies 3 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 low-
stress 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.

2                                                     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 in-
depth 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).


Page 3                                        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 PHMSA also has arrangements with the 48 contiguous states, the

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.
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.

4                                                      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 periodically 9 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 2002 10 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 2006 13
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.
10
    Pub. L. No. 107-355, § 14, 116 Stat. 2985, 3002 (Dec. 17, 2002).
11
    49 C.F.R. § part 192, subpart O.
12
    49 C.F.R. § 192.905.
13
    Pub. L. No. 109-468, § 9, 120 Stat. 3486 (2006).



Page 5                                                 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 method 17—in-


14
    49 C.F.R. part 192, subpart P.
15
    49 C.F.R. § 192.1005.
16
    74 Fed. Reg. 63934 (December 4, 2009). Comment topic 8.
17
 49 C.F.R. § 192.921.In general, the maximum reassessment interval allowable is seven years (49
C.F.R. § 192.939).


6                                                  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




18
  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. 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.
19
   Hydrostatic 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.
20
  Direct 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.
21
  All 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.




Page 7                                                    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
22
 In-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.


8                                                    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 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.




23
  Distribution 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 risk-
control 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.
24
 49 U.S.C. § 60118(c).



Page 9                                                  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 low-
stress 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
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,

25
 GAO, 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).
26
  Gas 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.
27
 Gas Research Institute, Leak versus Rupture Considerations for Steel Low-Stress Pipelines, GRI-
00/0232, (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.


10                                                    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
reporting 29—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 high-
consequence 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 Furthermore, according
to some PHMSA officials, lower stress transmission pipelines should be subject to

28
  According 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.
29
 49 C.F.R. §§ 191, 192, 193, and 195.
30
  Of 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.
31
 Of the 52 officials from state pipeline safety agencies surveyed, 12 responded that they had no
opinion on the matter.


Page 11                                                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)

12                                            GAO-12 389R Low–Stress Pipeline Regulations
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