Gas Pipeline Safety: Preliminary Observations on the Integrity
Management Program and 7-Year Reassessment Requirement
(16-MAR-06, GAO-06-474T).
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 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.
-------------------------Indexing Terms-------------------------
REPORTNUM: GAO-06-474T
ACCNO: A49197
TITLE: Gas Pipeline Safety: Preliminary Observations on the
Integrity Management Program and 7-Year Reassessment Requirement
DATE: 03/16/2006
SUBJECT: Accountability
Federal regulations
Gas pipeline operations
Industrial safety
Inspection
Occupational health and safety programs
Occupational safety
Pipeline operations
Program evaluation
Program management
Repairs
Risk assessment
Safety regulation
Safety standards
Strategic planning
******************************************************************
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GAO-06-474T
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
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.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,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.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.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.
1Under 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.
2GAO, 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).
In summary:
o 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.
o 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 replacement5-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.6
The existence of an overlap was an industry concern while the 2002
act was being debated.
o 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.
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.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.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.
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.9 Furthermore, in response to our
2002 recommendation,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.11
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.
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.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.
3Standards 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).
4The information that we obtained from the 25 operators is not necessarily
generalizable to all operators.
5Operators 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.
6Under 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.
Background
7An 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.
8Confirmatory 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.
Early Indications Suggest that Gas Integrity Management Enhances Public Safety,
but Operators Raise Some Concerns About Implementation
9In-line inspections are accomplished by running specialized tools through
pipelines to detect problems, such as reduced wall thickness and cracks.
10GAO, Pipeline Safety and Security: Improved Workforce Planning and
Communication Needed, GAO-02-785 (Washington, D.C.: Aug. 26, 2002).
11Twenty-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.
7-Year Reassessment Requirement May be Appropriate for Some Operators but
Conservative for Others
Operators Favor a Risk-based, Rather than a One-Size-Fits-All Reassessment
Standard
12Pipeline 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.
Figure 1: Number of Immediate Repairs Needed as Found During Baseline
Assessments
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.
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.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.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.15
13Prevention 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.
14On 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.
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.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.17
15Direct 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.
16To prepare for this hearing, we contacted the Inline Inspection
Association, one company offering in-line inspection services, and two
companies offering direct assessment services.
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.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).
17According 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.
18The 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.
Figure 2: Operators' Planned Baseline Assessment and Reassessment
Schedules
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.
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 [email protected] . 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.
(542087)
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www.gao.gov/cgi-bin/getrpt? GAO-06-474T .
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Highlights of GAO-06-474T , a testimony before the Subcommittee on
Highways, Transit and Pipelines, Committee on Transportation and
Infrastructure, House of Representatives
March 16, 2006
GAS PIPELINE SAFETY
Preliminary Observations on the Integrity Management Program and 7-Year
Reassessment Requirement
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.
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
*** End of document. ***