Gas Pipeline Safety
Preliminary Observations on the Integrity Management Program and 7-Year Reassessment Requirement Gao ID: GAO-06-474T March 16, 2006About a dozen people are killed or injured in natural gas transmission pipeline incidents each year. In an effort to improve upon this safety record, the Pipeline Safety Improvement Act of 2002 requires that operators assess pipeline segments in about 20,000 miles of highly populated or frequented areas for safety risks, such as corrosion, welding defects, or incorrect operation. Half of these baseline assessments must be done by December 2007, and the remainder by December 2012. Operators must then repair or replace any defective pipelines, and reassess these pipeline segments for corrosion damage at least every 7 years. The Pipeline and Hazardous Materials Safety Administration (PHMSA) administers this program, called gas integrity management. This testimony is based on ongoing work for Congress, as required by the 2002 act. The testimony provides preliminary results on the safety effects of (1) PHMSA's gas integrity management program and (2) the requirement that operators reassess their natural gas pipelines at least every 7 years. It also discusses how PHMSA has acted to strengthen its enforcement program in response to recommendations GAO made in 2004. GAO expects to issue two reports this fall that will address these and other topics.
Early indications suggest that the gas transmission pipeline integrity management program enhances public safety by supplementing existing safety standards with risk-based management principles. Operators have reported that they have assessed about 6,700 miles as of December 2005 and completed 338 repairs for problems they are required to address immediately. Operators told GAO that the primary benefit of the program is the comprehensive knowledge they must acquire about the condition of their pipelines. For some operators, the integrity management program has prompted such assessments for the first time. Operators raised concerns about (1) their uncertainty over the level of documentation that PHMSA requires and (2) whether their pipelines need to be reassessed at least every 7 years. The 7-year reassessment requirement is generally consistent with the industry consensus standard of at least every 5 to 10 years for reassessing pipelines operating under higher stress (higher operating pressure in relation to wall strength). The majority of transmission pipelines in the U.S. are estimated to be higher stress pipelines. However, most operators told GAO that the 7-year requirement is conservative for pipelines that operate under lower stress because they found few problems requiring reassessments earlier than the 15 to 20 years under the industry standard. Operators GAO contacted said that periodic reassessments are beneficial for finding and preventing problems; but they favored reassessments on severity of risk rather than a one-size-fits-all standard. Operators did not expect that the existence of an "overlap period" from 2010 through 2012, when operators will be conducting baseline assessments and reassessments at the same time, would create problems in finding resources to conduct reassessments. PHMSA has developed a reasonable enforcement strategy framework that is responsive to GAO's earlier recommendations. PHMSA's strategy is aimed at reducing pipeline incidents and damage through direct enforcement and through prevention involving the pipeline industry and stakeholders (such as state regulators). Among other things, the strategy entails (1) using risk-based enforcement and dealing severely with significant noncompliance and repeat offenses, (2) increasing knowledge and accountability for results by clearly communicating expectations for operators' compliance, (3) developing comprehensive guidance tools and training inspectors on their use, and (4) effectively using state inspection capabilities.
GAO-06-474T, Gas Pipeline Safety: Preliminary Observations on the Integrity Management Program and 7-Year Reassessment Requirement
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Testimony:
Before the Subcommittee on Highways, Transit and Pipelines, Committee
on Transportation and Infrastructure, House of Representatives:
United States Government Accountability Office:
GAO:
For Release on Delivery Expected at 10:00 a.m. EST:
Thursday, March 16, 2006:
Gas Pipeline Safety:
Preliminary Observations on the Integrity Management Program and 7-Year
Reassessment Requirement:
Statement of Katherine Siggerud, Director:
Physical Infrastructure Issues:
GAO-06-474T:
GAO Highlights:
Highlights of GAO-06-474T, a testimony before the Subcommittee on
Highways, Transit and Pipelines, Committee on Transportation and
Infrastructure, House of Representatives:
Why GAO Did This Study:
About a dozen people are killed or injured in natural gas transmission
pipeline incidents each year. In an effort to improve upon this safety
record, the Pipeline Safety Improvement Act of 2002 requires that
operators assess pipeline segments in about 20,000 miles of highly
populated or frequented areas for safety risks, such as corrosion,
welding defects, or incorrect operation. Half of these baseline
assessments must be done by December 2007, and the remainder by
December 2012. Operators must then repair or replace any defective
pipelines, and reassess these pipeline segments for corrosion damage at
least every 7 years. The Pipeline and Hazardous Materials Safety
Administration (PHMSA) administers this program, called gas integrity
management.
This testimony is based on ongoing work for this Subcommittee and for
other committees, as required by the 2002 act. The testimony provides
preliminary results on the safety effects of (1) PHMSA‘s gas integrity
management program and (2) the requirement that operators reassess
their natural gas pipelines at least every 7 years. It also discusses
how PHMSA has acted to strengthen its enforcement program in response
to recommendations GAO made in 2004.
GAO expects to issue two reports this fall that will address these and
other topics.
What GAO Found:
Early indications suggest that the gas transmission pipeline integrity
management program enhances public safety by supplementing existing
safety standards with risk-based management principles. Operators have
reported that they have assessed about 6,700 miles as of December 2005
and completed 338 repairs for problems they are required to address
immediately. Operators told GAO that the primary benefit of the program
is the comprehensive knowledge they must acquire about the condition of
their pipelines. For some operators, the integrity management program
has prompted such assessments for the first time. Operators raised
concerns about (1) their uncertainty over the level of documentation
that PHMSA requires and (2) whether their pipelines need to be
reassessed at least every 7 years.
The 7-year reassessment requirement is generally consistent with the
industry consensus standard of at least every 5 to 10 years for
reassessing pipelines operating under higher stress (higher operating
pressure in relation to wall strength). The majority of transmission
pipelines in the U.S. are estimated to be higher stress pipelines.
However, most operators told GAO that the 7-year requirement is
conservative for pipelines that operate under lower stress because they
found few problems requiring reassessments earlier than the 15 to 20
years under the industry standard. Operators GAO contacted said that
periodic reassessments are beneficial for finding and preventing
problems; but they favored reassessments on severity of risk rather
than a one-size-fits-all standard. Operators did not expect that the
existence of an ’overlap period“ from 2010 through 2012, when operators
will be conducting baseline assessments and reassessments at the same
time, would create problems in finding resources to conduct
reassessments.
PHMSA has developed a reasonable enforcement strategy framework that is
responsive to GAO‘s earlier recommendations. PHMSA‘s strategy is aimed
at reducing pipeline incidents and damage through direct enforcement
and through prevention involving the pipeline industry and stakeholders
(such as state regulators). Among other things, the strategy entails
(1) using risk-based enforcement and dealing severely with significant
noncompliance and repeat offenses, (2) increasing knowledge and
accountability for results by clearly communicating expectations for
operators‘ compliance, (3) developing comprehensive guidance tools and
training inspectors on their use, and (4) effectively using state
inspection capabilities.
Pipeline Failure Resulting from Corrosion:
[See PDF for image]
[End of figure]
www.gao.gov/cgi-bin/getrpt?GAO-06-474T.
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.
[End of section]
Mr. Chairman and Members of the Subcommittee:
We appreciate the opportunity to participate in this oversight hearing
on the Pipeline Safety Improvement Act of 2002. The act strengthens
federal pipeline safety programs and enforcement, state oversight of
pipeline operators, and public education on pipeline safety. The
information that we and others will provide today should help the
Congress as it prepares to reauthorize pipeline safety programs.
My statement is based on the preliminary results of our ongoing work
for this Subcommittee and others. As directed by the 2002 act, we are
assessing the effects on safety stemming from (1) the Pipeline and
Hazardous Materials Safety Administration's (PHMSA) integrity
management program for gas transmission pipelines and (2) the
requirement that pipeline operators reassess their natural gas
pipelines for certain safety risks at least every 7 years.[Footnote 1]
In addition, I would also like to briefly touch on how PHMSA has acted
to strengthen its enforcement program. I testified on PHMSA's
enforcement program before this Subcommittee almost 2 years
ago,[Footnote 2] and believe that this is a good opportunity to update
you on some positive accomplishments.
Our work is based on our review of laws, regulations, and other PHMSA
guidance, as well as discussions with a broad range of stakeholders,
including industry trade associations, pipeline safety advocate groups,
state pipeline regulators, and consensus standards
organizations.[Footnote 3] In addition, we contacted 25 pipeline
operators about the matters that I will discuss today. We chose
operators for which integrity management could have the greatest
impact, all else being equal: larger and smaller operators with the
highest proportion of pipelines in highly populated or frequented areas
to total miles of pipeline. These operators represent about half of the
miles of pipeline assessed to date.[Footnote 4] We relied on pipeline
operators' professional judgment in reporting on the conditions that
they found during their assessments of safety risks. 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 March 2006.
In summary:
* Implementation of integrity management is in its early stages as
PHMSA's regulations were finalized in 2004. Early indications suggest
that the gas integrity management program has enhanced public safety by
requiring that operators identify and address the risks to pipeline
segments located in areas that are most likely to affect public safety.
Operators believe that the primary benefit of the program is the
comprehensive knowledge they must acquire about the condition of their
pipelines. However, operators have raised concerns about (1) their
uncertainty over the level of documentation required by the program and
(2) whether the requirement to reassess their pipelines at least every
7 years contributes to increased safety. PHMSA's initial inspections of
11 operators' integrity management programs have shown that operators
are doing well in assessing their pipelines and making repairs but that
they need to better document their management practices and decisions.
* Overall, pipeline operators have reported to PHMSA that, in the
almost 6,700 miles of pipeline they have assessed, they have found 338
problems that required immediate repair or replacement[Footnote 5]--
about 1 problem every 20 miles, on average. The 25 operators that we
contacted--which represent about half of the 6,700 miles assessed so
far--told us that, if the 7-year requirement were not in place, they
would reassess the pipeline segments located in highly populated or
frequented areas every 10, 15, or 20 years following industry consensus
standards. The 7-year reassessment requirement is similar to industry
standards for pipelines operating under higher-stress (higher operating
pressure in relation to wall strength) where the industry standard for
reassessments is no more than 5 to 10 years, depending on operating
pressure. However, operators told us that the 7-year reassessment
requirement is conservative for pipelines operating under lower-stress,
where the industry reassessment standard can extend to 15 to 20 years.
The large majority of transmission pipelines in the U.S. are estimated
to be higher-stress pipelines, based on information from industry
associations. Most operators of lower-stress pipelines told us that
they found few problems during baseline assessments that would require
reassessments before 15 or 20 years. Operators that we contacted
believed that periodic reassessments of their pipelines will be
beneficial in finding and preventing problems. However, they favored
conducting reassessments based on severity of risk rather than applying
a one-size-fits-all standard. Operators did not expect that the
existence of an "overlap period" from 2010 through 2012, when operators
will be completing baseline assessments and beginning reassessments at
the same time, would create problems in finding resources to conduct
reassessments.[Footnote 6] The existence of an overlap was an industry
concern while the 2002 act was being debated.
* PHMSA has developed a reasonable enforcement strategy framework that
is responsive to the recommendations that we made in 2004. PHMSA's
strategy is aimed at reducing pipeline incidents and damage through
both direct enforcement and prevention. The strategy entails, among
other things, (1) using risk-based enforcement that clearly reflects
potential risk and seriousness and dealing severely with operators'
significant noncompliance and repeat offenses; (2) increasing knowledge
and accountability for results by clearly communicating expectations
for operator compliance; (3) developing comprehensive guidance tools,
along with training inspectors on their use; and (4) effectively using
state inspection capabilities:
Background:
On average, about 3 people have died and about 8 people have been
injured each year over the last 10 years in natural gas transmission
pipeline incidents. The number of incidents has increased from 77 in
1996 to 122 and 200 in 2004 and 2005, respectively, mostly reflecting
more frequent occurrence of property damage.[Footnote 7] Much of this
increase may be attributed to increases in the price of gas (which has
the effect of lowering the reporting threshold) over the past several
years and to damage as a result of hurricanes in 2005.
As a means of enhancing the security and safety of gas pipelines, the
2002 act included an integrity management structure that, in part,
requires that operators of gas transmission pipelines systematically
assess for safety risks the portions of their pipelines located in
highly populated or frequently used areas, such as parks. Safety risks
include corrosion, welding defects and failures, third-party damage
(e.g., from excavation equipment), land movement, and incorrect
operation. The act requires that operators perform these assessments
(called baseline assessments) on half of the pipeline mileage in highly
populated or frequented areas by December 2007 and the remainder by
December 2012. Those pipeline segments potentially facing the greatest
risks are to be assessed first. Operators must then repair or replace
defective pipelines. Risk-based assessments are seen by many as having
a greater potential to improve safety than focusing on compliance with
safety standards regardless of the threat to pipeline safety.
The act further provides that pipeline segments in highly populated or
frequented areas must be reassessed for safety risks at least every 7
years. PHMSA's regulations implemented the act by requiring that
operators reassess their pipelines for corrosion damage every 7 years,
using an assessment technique called confirmatory direct
assessment.[Footnote 8] Under these regulations, and consistent with
industry national consensus standards, operators must also reassess
their pipeline segments for any safety risk at least every 5, 10, 15,
or 20 years, depending on the pressure under which the pipeline
segments are operated and the condition of the pipeline.
There are about 900 operators of about 300,000 miles of gas
transmission and gathering pipelines in the United States. As of
December 2005, according to PHMSA, 429 of these operators reported that
about 20,000 miles of their pipelines lie in highly populated or
frequented areas (about 7 percent of all transmission pipeline miles).
Operators reported that they had as many as about 1,600 miles and as
few as 0.02 miles of pipeline in these areas.
PHMSA, within the Department of Transportation, administers the
national regulatory program to ensure the safe transportation of gas
and hazardous liquids (e.g., oil, gasoline, and anhydrous ammonia) by
pipeline. The agency attempts to ensure the safe operation of pipelines
through regulation, national consensus standards, research, education
(e.g., to prevent excavation-related damage), oversight of the industry
through inspections, and enforcement when safety problems are found.
PHMSA employs about 165 staff in its pipeline safety program, about
half of whom are pipeline inspectors who inspect gas and hazardous
liquid pipelines under integrity management and other more traditional
compliance programs. Nine PHMSA inspectors are currently devoted to the
gas integrity management program. In addition, PHMSA is assisted by
inspectors in 48 states, the District of Columbia, and Puerto Rico.
Early Indications Suggest that Gas Integrity Management Enhances Public
Safety, but Operators Raise Some Concerns About Implementation:
While the gas integrity management program is still being implemented,
early indications suggest that it enhances public safety by
supplementing existing safety standards with risk-based management
principles. Prior to the integrity management program, there were, and
still are, minimum safety standards that operators must meet for the
design, construction, testing, inspection, operation, and maintenance
of gas transmission pipelines. These standards apply equally to all
pipelines and provide the public with a basic level of protection from
pipeline failures. However, minimum standards do not require operators
to identify and address risks that are specific to their pipelines nor
do they require operators to assess the integrity of their pipelines.
While some operators did assess the integrity of some of their
pipelines, others did not. Some pipelines have been in operation for 40
or more years with no assessment. The gas integrity management
requirements, finalized in 2004, go beyond the existing safety
standards by requiring operators, regardless of size, to routinely
assess pipelines in highly populated or frequented areas for specific
threats, take action to mitigate the threats, and document management
practices and decision-making processes.
Representatives from the pipeline industry, safety advocate groups, and
operators we have contacted agree that the integrity management program
enhances public safety. Some operators noted that, although the
program's requirements can be costly and time consuming to implement,
the benefits to date are worth the cost. The primary benefit identified
was the comprehensive knowledge the program requires all operators to
have of their pipeline systems. For example, under integrity
management, operators must gather and analyze information about their
pipelines in highly populated or frequented areas to get a complete
picture of the condition of those lines. This includes developing maps
of the pipeline system and information on corrosion protection, exposed
pipeline, threats from excavation or other third-party damage, and the
installation of automatic shut off valves. Another benefit cited was
improved communications within the company. Investigations of pipeline
incidents have shown that, in some cases, an operator possessed
information that could have prevented an incident but had not been
shared with employees who needed it most. Integrity management requires
operators to pull together pipeline data from various sources within
the company to identify threats to the pipelines, leading to more
interaction among different departments within pipeline companies.
Finally, integrity management focuses operator resources in those areas
where an incident could have the greatest impact.
While industry and operator representatives have provided examples of
the early benefits of integrity management, operators must report semi-
annually on performance measures that should quantitatively demonstrate
the impact of the program over time. These measures include the total
mileage of pipelines and the mileage of pipelines assessed in highly
populated or frequented areas, as well as the number of repairs made
and leaks, failures, and incidents identified in these areas. In the 2
years that operators have reported the results of integrity management,
they have assessed about 6,700 miles of their 20,000 miles of pipelines
located in highly populated or frequented areas and they have completed
338 repairs that were immediately required and another 998 repairs that
were less urgent. 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. For example, one operator told us that it had complied with
all the minimum safety standards on its pipeline, and the pipeline
appeared to be in good condition. The operator then assessed the
condition of a segment of the pipeline under its integrity management
program and found a serious problem causing it to shut the line down
for immediate repair.
One of the most frequently cited concerns by the 25 operators we
contacted was the uncertainty 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. Each operator must develop and document specific policies and
procedures to demonstrate their commitment to compliance and
implementation of the integrity management requirements. In addition,
an operator must document any decisions made related to integrity
management. For example, an operator must document how it identified
the threats to its pipeline in highly populated or frequented areas and
who was involved in identifying the threats, their qualifications, and
the data they used. While the operators we contacted did not disagree
with the need to document their policies and procedures, some said that
the detailed documentation required for every decision is very time
consuming and does not contribute to the safety of pipeline operations.
Moreover, they are concerned that they will not know if they have
enough documentation until their program has been inspected. After
conducting 11 inspections, PHMSA found that, while operators are doing
well in conducting assessments and making the identified repairs, they
are having difficulty overall in the development and documentation of
their management processes. Another concern raised by most of the
operators is the requirement to reassess their pipelines at least every
7 years. I will discuss the 7-year reassessment requirement in more
detail shortly.
As part of our assessment of the integrity management program, we are
also examining how PHMSA and state pipeline agencies plan to oversee
operator implementation of the program. To help federal and state
inspectors prepare for and conduct integrity management inspections,
PHMSA developed detailed inspection protocols tied to the integrity
management regulations and a series of training courses covering the
protocols and other relevant topics, such as corrosion and in-line
inspection.[Footnote 9] Furthermore, in response to our 2002
recommendation,[Footnote 10] PHMSA has been working to improve its
communication with states about their role in overseeing integrity
management programs. For example, PHMSA's efforts include (1) inviting
state inspectors to attend federal inspections, (2) creating a website
containing inspection information, and (3) providing a series of
updates through the National Association of Pipeline Safety
Representatives. I am pleased to report that preliminary results from
an ongoing survey of state pipeline agencies (with more than half the
states responding thus far) show that the majority of states that
reported believe that the communication from PHMSA has been very or
extremely useful in helping them understand their role and
responsibilities in conducting integrity management
inspections.[Footnote 11]
7-Year Reassessment Requirement May be Appropriate for Some Operators
but Conservative for Others:
Nationwide, pipeline operators reported to PHMSA that they have found,
on average, about one problem requiring immediate repair or replacement
for every 20 miles of pipeline assessed in highly populated or
frequented areas. Operators we contacted recognize the benefits of
reassessments; however, almost all would prefer following the industry
national consensus standards that use safety risk, rather than a
prescribed term, for determining when to reassess their pipelines. Most
operators expect to be able to acquire the services and tools needed to
conduct these reassessments including during an overlap period when
they are starting to reassess pipeline segments while completing
baseline assessments.
Operators Favor a Risk-based, Rather than a One-Size-Fits-All
Reassessment Standard:
As discussed earlier, as of December 2005, operators nationwide have
notified PHMSA of 338 problems that required immediate repair in the
6,700 miles they have assessed--about one immediate repair required for
every 20 miles of pipeline assessed in highly populated or frequented
areas.
The number of immediate repairs may be due, in part, to some operators
systematically assessing their pipelines for the first time as a result
of the 2002 act. Of the 25 transmission operators and local
distribution companies that we contacted, most told us that they found
few safety problems that required reducing pressure and performing
immediate repairs during baseline assessments covering (1) about 3,000
miles of pipeline in highly populated or frequented areas and about (2)
35,000 miles outside of these areas.[Footnote 12] (See fig. 1.) Most
operators reported finding pipelines in good condition and free of
major defects, requiring only minor repairs or recoating. A few
operators found more than 10 immediate repairs. Operators nonetheless
found these assessments valuable in determining the condition of their
pipelines and finding damage.
Figure 1: Number of Immediate Repairs Needed as Found During Baseline
Assessments:
[See PDF for image]
Note: To prevent distortion, we excluded 3 of the 25 operators we
contacted because they had assessed 0 miles of pipeline to date. This
figure includes the immediate repairs for pipeline located both inside
and outside of highly populated or frequented areas.
[End of figure]
Most of the operators told us that, if the 7-year reassessment
requirement was not in place, they would respond to the conditions that
they identified during baseline assessments by reassessing their
pipelines every 10, 15, or 20 years, based on industry consensus
standards. These baseline assessment findings suggest that--at least
for the operators we contacted--the 7-year requirement is conservative.
However, the 7-year reassessment requirement may be more appropriate
for higher-stress pipelines than for lower-stress pipelines.
The 7-year reassessment requirement is generally more consistent with
scientific-and engineering-based intervals for pipelines operating
under higher-stress. Higher-stress transmission pipelines are typically
those that transport natural gas across the country from a gathering
area to a local distribution company. For higher-stress pipelines, the
industry consensus standard sets maximum reassessment periods at 5 or
10 years, depending on operating pressure. PHMSA does not collect
information in such a way that would allow us to readily estimate the
percentage of all pipeline miles in highly populated or frequented
areas that operate under higher pressure. For the 25 operators that we
contacted, the operators told us that about three- fourths of their
pipeline mileage in highly populated or frequented areas operated at
higher pressures. Finally, industry data suggest that in the
neighborhood of 250,000 miles of the 300,000 miles (over 80 percent) of
all transmission pipelines nationwide may operate at higher pressure.
Some operators told us that the 7-year reassessment requirement is
conservative for pipelines that operate under lower-stress. This is
especially true for local distribution companies that use their
transmission lines mainly to transport natural gas under lower
pressures for several miles from larger cross-country lines in order to
feed smaller distribution lines. They pointed out, for example, that in
a lower-pressure environment, pipelines tend to leak rather than
rupture. Leaks involve controlled, slow emissions that typically create
little damage or risk to public safety. Most local distribution
companies we spoke with reported finding few, if any, conditions during
baseline assessments that would necessitate another assessment within 7
years. As a result, if the 7-year requirement did not exist, the local
distribution companies would likely reassess every 15 to 20 years
following industry consensus standards. Some of these operators often
pointed out that since third-party damage poses the greatest threat to
their systems. Operators added that third-party damage can happen at
any time and that prevention and mitigation measures are the best ways
to address it.[Footnote 13]
Operators viewed a risk-based reassessment requirement such as in the
consensus standard as valuable for public safety. Operators of both
higher-stress and lower-stress pipelines indicated a preference for a
risk-based reassessment requirement based on engineering standards
rather than a prescriptive one-size-fits-all standard.[Footnote 14]
Such a risk-based reassessment standard would be consistent with the
overall thrust of the integrity management program. Some operators
noted that reassessing pipeline segments with few defects every 7 years
takes resources away from riskier segments that require more attention.
While PHMSA's regulations require that pipeline segments be reassessed
only for corrosion problems at least every 7 years using a less
intensive assessment technique (confirmatory direct assessment) some
operators point out that it has not worked out that way. They told us
that, if they are going to the effort of assessing pipeline segments to
meet the 7-year reassessment requirement, they will typically use more
extensive testing--for both corrosion and for other problems--than
required, because doing so will provide more comprehensive information.
Thus, in most cases, operators plan to reassess their pipelines by
using in-line inspections or direct assessment for problems in addition
to corrosion sooner than required under PHMSA's rules.[Footnote 15]
Services and Tools Are Likely to be Available for Reassessments:
Most operators and inspection contractors we contacted told us that the
services and tools needed to conduct periodic reassessments will likely
be available to most operators. All of the operators reported that they
plan to rely on contractors to conduct all or a portion of their
reassessments and some have signed, or would like to sign, long-term
contracts that extend contractor services through a number of years.
However, few have scheduled reassessments with contractors, as they are
several years in the future, and operators are concentrating on
baseline assessments.
Nineteen of the 21 operators that reported both baseline and
reassessment schedules to us said that that they primarily plan to use
in-line inspection or direct assessment to reassess segments of their
pipelines located in highly populated or frequented areas. In-line
inspection contractors that we contacted report that there is capacity
within the industry to meet current and future operator demands. Unlike
the in-line inspection method, which is an established practice that
many operators have used on their pipelines at least once prior to the
integrity management program, the direct assessment method is new to
both contractors and operators. Direct assessment contractors told us
that there is limited expertise in this field and one contractor said
that newer contractors coming into the market to meet demand may not be
qualified.[Footnote 16] The operators planning to use direct assessment
for their pipelines are generally local distribution companies with
smaller diameter pipelines that cannot accommodate in-line inspection
tools.[Footnote 17]
An industry concern about the 7-year reassessment requirement is that
operators will be required to conduct reassessments starting in 2010
while they are still in the 10-year period (2003-2012) for conducting
baseline assessments. Industry was concerned that this could create a
spike in demand for contractor services resulting from an overlap of
assessments and reassessments from 2010 through 2012, and operators
would have to compete for the limited number of contractors to carry
out both. The industry was worried that operators might not be able to
meet the reassessment requirement and that it was unnecessarily
burdensome.[Footnote 18] Most operators that we contacted do not
anticipate a spike and baseline activity should decrease as they begin
to conduct reassessments. (See fig. 2.) They predict that operators
will have conducted a large number of baseline assessments between 2005
and 2007 in order to meet the statutory deadline for completing at
least half of their baseline assessments by December 2007 (2 years
before the predicted overlap).
Figure 2: Operators' Planned Baseline Assessment and Reassessment
Schedules:
[See PDF for image]
Note: This figure shows the baseline assessments conducted, or planned
to be conducted as well as the reassessments that are planned in highly
populated or frequented areas for the 20 of 25 operators we contacted.
Five operators did not report their reassessment plans.
[End of figure]
There has also been a concern about whether baseline assessments and
reassessments would affect natural gas supply if pipelines are taken
out of service or operate at reduced pressures when repairs are being
made. We are addressing this issue and will report on it in the fall.
PHMSA Has Developed a Reasonable Framework for Its Enforcement Program:
Recently, PHMSA reassessed its approach for enforcing pipeline safety
standards in response to our concern that it lacked a comprehensive
enforcement strategy. In August 2005, PHMSA adopted a strategy that
focuses on using risk-based enforcement, increasing knowledge of and
accountability for results, and improving its own enforcement
activities. The strategy also links these efforts to goals to reduce
and prevent incidents and damage, in addition to providing for periodic
assessment of results. While we have neither reviewed the revised
strategy in depth nor examined how it is being implemented, our
preliminary view is that it is a reasonable framework that is
responsive to the concerns that we raised in 2004.
PHMSA has established overall goals for its enforcement program to
reduce incidents and damage due to operators' noncompliance. PHMSA also
recognizes that incident and damage prevention is important, and its
strategy includes a goal to influence operators' actions to this end.
To meet these goals, PHMSA has developed a multi-pronged strategy that
is directed at the pipeline industry and stakeholders (such as state
regulators), and ensuring that its processes make effective use of its
resources.
For example, PHMSA's strategy calls for using risk-based enforcement
to, among other things, take enforcement actions that clearly reflect
potential risk and seriousness and deal severely with significant
operator noncompliance and repeat offenses. Second, the strategy calls
for increasing knowledge and accountability for results through such
actions as (1) soliciting input from operators, associations, and other
stakeholders in developing and refining regulations, inspection
protocols, and other guidance; (2) clearly communicating expectations
for compliance and sharing lessons learned; and (3) assessing operator
and industry compliance performance and making this information
available. Third, the strategy, among other things, calls for improving
PHMSA's own enforcement activities through developing comprehensive
guidance tools and training inspectors on their use, and effectively
using state inspection capabilities.
Finally, to understand progress being made in encouraging pipeline
operators to improve their level of safety and, as a result, reduce
accidents and fatalities, PHMSA annually will assess its overall
enforcement results as well as various components of the program. Some
of the program elements that it may assess are inspection and
enforcement processes, such as the completeness and availability of
compliance guidance, the presentation of operator and industry
performance data, and the quality of inspection documentation and
evidence.
Concluding Observations:
Our work to date suggests that PHMSA's gas integrity management program
should enhance pipeline safety, and operators support it. We have not
identified major issues that need to be addressed at this time. We
expect to provide additional insights into these issues when we report
to this Subcommittee and others this fall.
Because the program is in its early phase of implementation, PHMSA is
learning how to oversee the program and operators are learning how to
meet its requirements. Similarly, operators are in the early stages of
assessing their pipelines for safety problems. This means that the
integrity management program will be going through this shake down
period for another year or two as PHMSA and operators continue to gain
experience.
Mr. Chairman, this concludes my prepared statement. I would be pleased
to respond to any questions that you or the other Members of the
Subcommittee might have.
GAO Contacts and Staff Acknowledgement:
For further information on this testimony, please contact Katherine
Siggerud at (202) 512-2834 or siggerudk@gao.gov. Individuals making key
contributions to this testimony were Jennifer Clayborne, Anne Dilger,
Seth Dykes, Maria Edelstein, Heather Frevert, Matthew LaTour, Bonnie
Pignatiello Leer, James Ratzenberger, and Sara Vermillion.
FOOTNOTES
[1] Under integrity management, operators systematically assess the
portions of their pipelines that are in highly populated or frequented
areas (such as parks) for safety risks. Although the gas integrity
management program applies to natural, toxic, and corrosive gases, the
overwhelming majority of gas pipelines in the United States carry
natural gas. Our work therefore focuses on natural gas. Transmission
pipelines transport gas products from sources to communities and are
primarily interstate. Distribution pipelines (local distribution
companies) that carry natural gas to ultimate users, such as homes, are
not subject to the 2002 act unless they are operated by companies that
also operate transmission pipelines.
[2] GAO, Pipeline Safety: Preliminary Information on the Office of
Pipeline Safety's Efforts to Strengthen Its Enforcement Program, GAO-04-
875T (Washington, D.C.: June 16, 2004) and GAO, Pipeline Safety:
Management of the Office of Pipeline Safety's Enforcement Program Needs
Further Strengthening, GAO-04-801 (Washington, D.C.: July 23, 2004).
[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. PHMSA's regulations
incorporate reassessment standards developed by the American Society of
Mechanical Engineers: Managing the System Integrity of Gas Pipelines
(ASME B31.8S-2004).
[4] The information that we obtained from the 25 operators is not
necessarily generalizable to all operators.
[5] Operators have reported that about 20,000 miles of pipelines are
located in highly populated or frequented areas. Operators are required
to make immediate repairs to their pipelines if they (1) determine the
remaining strength of the pipe shows a predicted failure pressure of
less than or equal to 1.1 times the maximum allowable operating
pressure; (2) identify a dent that has any indication of metal loss,
cracking, or a stress riser; or (3) determine, in their judgment, the
assessment results require immediate action.
[6] Under the 2002 act, operators have until 2012 to complete their
baseline assessments. However, under the 7-year reassessment
requirement, operators that started their baseline assessments in 2003
would then need to reassess those pipeline segments in 2010.
[7] An incident, for PHMSA reporting purposes, involves a death; injury
requiring hospitalization; or property damage, including the price of
natural gas lost during an incident, of $50,000 or more.
[8] Confirmatory direct assessment uses principles and techniques of
direct assessment to identify internal and external corrosion of
pipelines. Under confirmatory direct assessment, operators can meet
PHMSA's rules by using a single assessment tool, rather than several
tools or approaches that would provide more comprehensive information.
[9] In-line inspections are accomplished by running specialized tools
through pipelines to detect problems, such as reduced wall thickness
and cracks.
[10] GAO, Pipeline Safety and Security: Improved Workforce Planning and
Communication Needed, GAO-02-785 (Washington, D.C.: Aug. 26, 2002).
[11] Twenty-nine states responded to the survey as of early March 2006.
Three states indicated that PHMSA information was extremely useful, 15
states said the information was very useful, 3 states said it was
moderately useful, 4 said it was somewhat useful, and 4 had no opinion.
[12] Pipeline operators, for example, told us that, when they run an in-
line inspection tool through a pipeline, they will not collect data
solely within the boundary of the highly populated or frequented area
if the insertion and retrieval points for the tool extend beyond the
highly populated or frequented area. Rather, they gather information on
the pipeline's condition for the entire distance between the insertion
and retrieval points because, in doing so, they gather additional
insights into the condition of their pipeline.
[13] Prevention and mitigation measures include one-call programs,
proper marking of the pipeline's location, inspection by air, and
public education programs. In one-call programs, persons who want to
dig in an area contact a clearinghouse. The clearinghouse notifies
pipeline operators and others that someone is going to be digging near
their pipeline, so that the operator can mark the pipeline's location
prior to the digging work.
[14] On a related note, the Congress expressed a general preference for
technical standards developed by consensus bodies over agency-unique
standards in the National Technology Transfer and Advancement Act of
1995.
[15] Direct assessment is used to identify corrosion and other defects
in pipelines. It is used when in-line inspection cannot be used and to
avoid interrupting gas supply to a community fed by a single pipeline.
Direct assessment involves several steps, including digging holes at
intervals along a pipeline to examine suspected problem areas.
[16] To prepare for this hearing, we contacted the Inline Inspection
Association, one company offering in-line inspection services, and two
companies offering direct assessment services.
[17] According to industry estimates, 35 percent of all local
distribution company pipelines (as measured in miles likely to be
located in highly populated areas) cannot accommodate an in-line
inspection tool, compared to only about 4 percent of transmission
operators' pipelines.
[18] The 2002 act allows operators to request a waiver from conducting
reassessments when inspection tools are not available and when
operators need to maintain product supply. PHMSA has not issued
guidance on conditions under which it would grant a waiver.
