Gas Pipeline Safety
Preliminary Observations on the Implementation of the Integrity Management Program Gao ID: GAO-06-588T April 27, 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 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. This testimony also discusses how PHMSA has strengthened its enforcement program in response to recommendations GAO made in 2004.
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 10 years (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 lower stress pipelines operators told GAO that the 7-year requirement is conservative for their pipelines 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-06-588T, Gas Pipeline Safety: Preliminary Observations on the Implementation of the Integrity Management Program
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Testimony:
Before the Subcommittee on Energy and Air Quality, Committee on Energy
and Commerce, House of Representatives:
United States Government Accountability Office:
GAO:
For Release on Delivery Expected at 10:00 a.m. EST:
Thursday, April 27, 2006:
Gas Pipeline Safety:
Preliminary Observations on the Implementation of the Integrity
Management Program:
Statement of Katherine Siggerud, Director Physical Infrastructure
Issues:
GAO-06-588T:
GAO Highlights:
Highlights of GAO-06-588T, a testimony before the Subcommittee on
Energy and Air Quality, Committee on Energy and Commerce, 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 10 years (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 lower stress pipelines operators told GAO that
the 7-year requirement is conservative for their pipelines 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.
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 agencies, pipeline inspection contractors, and consensus
standards organizations.[Footnote 3] In addition, we surveyed the 47
state pipeline agencies responsible for inspecting intrastate gas
transmission pipeline operators on their plans for conducting
inspections of operators' integrity management programs.[Footnote 4] We
also contacted 41 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 60 percent of the miles of pipeline assessed to date.
We relied on pipeline operators' professional judgment in reporting on
the conditions that they found during their assessments of safety
risks. The information that we obtained from the 41 operators is not
necessarily generalizable to all operators. 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 April 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
13 interstate 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. Most state pipeline officials reported that
they have started or will start integrity management inspections of
intrastate operators this year. While state officials reported that
they generally agree that integrity management enhances public safety,
most are facing challenges in the areas of staffing and training.
* Overall, pipeline operators have reported to PHMSA that, in the 6,700
miles of pipeline in highly populated or frequented areas 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 41 operators that we contacted--which represent about 60 percent 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.[Footnote 6] The 7-
year reassessment requirement reflects a midpoint in relation to
industry standards for pipelines operating under higher stress
(pipelines with higher operating pressure in relation to wall strength)
where as the industry standard for reassessments is 10 years or less.
(The industry standard requires that pipelines be reassessed at least
every 5 years if all repairs are not made. PHMSA's regulations require
that repairs be made as necessary.) However, operators told us that the
7-year reassessment requirement is conservative for pipelines operating
under lower stress, where as 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 (21 of the 26 we contacted) 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 would 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 told us that requiring that pipelines
be reassessed more frequently than required under industry standards
increases costs--which are ultimately passed to consumers--but does not
increase safety. Operators did not expect that the existence of an
"overlap period" from 2010 through 2012, when operators will be
completing baseline assessments and beginning some reassessments at the
same time, would create problems in finding resources to conduct
reassessments.[Footnote 7] The existence of an overlap had been an
industry concern while the 2002 act was being debated.
* PHMSA has developed a reasonable enforcement strategy framework that
is responsive to concerns we raised in 2004 that PHMSA had not
incorporated into its enforcement strategy key features of effective
program management--clear program goals, a well-defined strategy for
achieving those goals, and performance measures linked to the program
goals. PHMSA's recently developed 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 of and accountability for
results by clearly communicating expectations for operators'
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 annually over the last 10 years in natural gas transmission
pipeline incidents. The number of incidents has increased from 77 in
1996 to 122 in 2004 and 200 in 2005, primarily due to the greater
frequency of property damage.[Footnote 8] Much of this increase may be
attributed to the rise 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 operators of gas transmission pipelines to 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
any defective pipelines. Performing this form of risk-based assessment
is 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 9] Under these regulations, and mostly consistent
with industry national consensus standards,[Footnote 10] operators must
also reassess their pipeline segments for safety risks at least every
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 are located 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. In
general, PHMSA retains full responsibility for inspecting and enforcing
regulations on interstate pipelines but certifies states to perform
these functions for intrastate pipelines. 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. State pipeline agencies have about 325 inspectors,
about 100 of which are currently able to perform integrity management
inspections of intrastate gas transmission pipeline operators in 47
states.
Early Indications Suggest that Gas Integrity Management Enhances Public
Safety, but Operators and States 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 have assessed the integrity of some of their
pipelines, others have not. Consequently, some pipelines have operated
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, to take action to mitigate the threats, and to document
management practices and decision-making processes.
Representatives from the pipeline industry, safety advocate groups,
state pipeline agencies, 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 costs. 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 gathering
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 shared it 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 on 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
semiannually 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 41 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 its commitment to compliance with 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 agreed 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 13 inspections, PHMSA found that, while interstate 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.
In response to our survey, most state officials indicated that the two
most challenging areas for them as they begin implementing gas
integrity management inspections are staffing and training. While most
state agencies currently have at least two inspectors that can perform
inspections of operators' integrity management programs, some state
pipeline officials responded that they do not have enough inspectors
for the increased workload and/or their inspectors have not completed
the training required by PHMSA. To ensure that inspectors have the
technical expertise to conduct integrity management inspections,
including evaluating operators' processes and decisions, PHMSA requires
inspectors to complete 4 classroom and 6 computer-based courses,
totaling about 19 days of training. Three of the classroom courses are
part of PHMSA's core training for all inspectors and are generally
offered annually. The fourth course--a new course that PHMSA
established for integrity management--was made available to two
inspectors from each state in 2005 and is now offered when there is
sufficient demand. The computer-based courses were made available to
the states starting in February 2005. While the state officials we
spoke with agree that the training is necessary, they are concerned
about the amount of time it takes to complete the required training and
the limited availability of the classroom training. We will continue to
follow up with state agencies about how these challenges will affect
their oversight activities.
I am pleased to report that in response to our 2002
recommendation,[Footnote 11] 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 Web site
containing inspection information, and (3) providing a series of
updates through the National Association of Pipeline Safety
Representatives. Results from the survey of state pipeline agencies
(with most of the states responding thus far) show that the majority of
state agencies believe that communication from PHMSA has been very or
extremely useful in helping them understand their roles and
responsibilities in conducting integrity management
inspections.[Footnote 12]
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 the 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 in highly populated or frequented areas that they have
assessed--about one immediate repair required for every 20 miles of
pipeline assessed in highly populated or frequented areas.[Footnote 13]
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.
We contacted 41 transmission operators and local distribution companies
about their assessment activities. These operators represent about 60
percent of the 6,700 miles assessed nationwide. Of these, 38 have begun
assessments and 32 (84 percent) told us that they found few safety
problems that required reducing pressure and performing immediate
repairs during baseline assessments. These assessments covered (1)
about 4,100 miles of pipeline in highly populated or frequented areas
and (2) about 30,000 miles outside of these areas.[Footnote 14] (See
fig. 1.) Twenty-five of these 38 operators reported finding pipelines
in good condition and free of major defects, requiring only minor
repairs or recoating. Seven of these operators found two or fewer
problems per 100 miles that require immediate repairs. Finally, six
operators found five or more immediate repairs per 100 miles
assessed.[Footnote 15] Operators nonetheless found these assessments
valuable in determining the condition of their pipelines and finding
damage. The large proportion of these operators reporting that they
found no or few problems requiring immediate repair is encouraging if
they represent assessments of their segments facing the greatest risk,
as required by the 2002 act.
Figure 1: Number of Immediate Repairs Needed as Found During Baseline
Assessments:
[See PDF for image]
Note: The Hi and Lo prefixes to the operator designations denote higher
stress and lower stress pipelines, respectively. To prevent distortion,
we excluded 3 of the 41 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.
The results for operator Hi12 show a greater number of problems
requiring immediate repair (per 100 miles assessed) because it has
assessed 11 miles and found 2 of these problems. The other two
operators showing the largest number of problems per 100 miles
requiring immediate repair, Lo25 and Lo26 have assessed 77 miles and
370 miles, respectively.
[End of figure]
Of the 38 operators that have begun assessment activities, 22 have
calculated reassessment intervals.[Footnote 16] These operators
indicated that based on the conditions that they identified during
baseline assessments; they could reassess their pipelines at intervals
of 10, 15, or 20 years --as allowed by industry consensus
standards[Footnote 17] --if the 7-year reassessment requirement were
not in place. In some cases, operators chose to reassess their
pipelines at intervals shorter than the industry standards based on
their own discretion. These baseline assessment findings suggest that
overall--at least for the operators we contacted--the 7-year
requirement is conservative.
The 7-year reassessment interval represents an approximate midpoint
between the 5-and 10-year industry reassessment requirements for
pipelines operating under higher-stress. (The industry standard
requires that pipelines be reassessed at least every 5 years if all
repairs are not made. PHMSA's regulations require that repairs be made
as necessary.) Higher-stress transmission pipelines are typically those
that transport natural gas across the country from a gathering area to
a local distribution company. Operators pointed out that reassessing
their pipelines in 7 rather than 10 years creates additional costs
without an equivalent gain in safety; that is, if the 7-year interval
requirement were not in place they would not reassess their pipelines
for another 3 years consistent with industry standards. Operators added
that the costs of the more frequent reassessments will eventually be
passed on to customers. 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. In the aggregate, the 41 operators that we
contacted told us that more than three-fourths of their pipeline
mileage in highly populated or frequented areas is operated under
higher pressure. 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 under 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 pressure
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 pose little
damage or risk to public safety. Twenty-one of the 26 lower stress
operators (most of which are local distribution companies) we contacted
that have begun assessments reported finding few, if any, conditions
during baseline assessments that would require immediate repair. (See
fig. 1 and accompanying note.) As a result, if the 7-year requirement
did not exist, these local distribution companies would likely reassess
every 15 to 20 years, following industry consensus standards. Some of
these operators pointed out that third-party damage poses the greatest
threat to their systems. Operators added that third-party damage, such
as dents caused by excavation, can happen at any time and that
prevention and mitigation measures are the best ways to address
it.[Footnote 18]
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 19] In
addition, 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 the less
intensive assessment technique of 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--both for corrosion and other problems--than
required, because doing so will provide more comprehensive information.
Thus, in most cases, operators plan to reassess their pipelines by
using the more extensive in-line inspections or direct assessment for
problems in addition to corrosion sooner than required under PHMSA's
rules.[Footnote 20]
Finally, operators are required by PHMSA to take actions in addition to
periodically reassessing their pipelines. Operators must, on an ongoing
basis, evaluate their pipelines by integrating operational data with
other information, including assessment data and risk assessment
information, to assure the integrity of their pipelines. Operators will
use the results from the evaluation to identify and remediate specific
pipeline threats and associated risks.
Services and Tools Are Likely to be Available for Reassessments:
Thirty-four of the 41 operators and 4 inspection contractors and 1
association we contacted (85 percent) told us that the services and
tools needed to conduct periodic reassessments will likely be available
to most operators.[Footnote 21] All but one of the operators reported
that they plan to rely on contractors to conduct all or a portion of
their reassessments, and eight of the 41 operators 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 reassessments will take place several years in the
future, and operators are concentrating on baseline assessments.
Thirty of the 38 operators (79 percent) that reported both baseline and
reassessment schedules to us said 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 25
of 41 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. 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 22]
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 is 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 23] However, the information provided by the
operators that we contacted does not suggest a spike and because
baseline assessment activity should decrease as they begin to conduct
reassessments. (See fig. 2.) Operators predict that they 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 -two 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 38 of 41 operators we
contacted. Three operators did not report their reassessment plans.
[End of figure]
There has also been a concern about whether baseline assessments and
reassessments would affect the natural-gas supply if pipelines are
taken out of service or operate at reduced pressure 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:
In 2004, we concluded that we could not assess the effectiveness of
PHMSA's enforcement strategy because it had not incorporated key
features of effective program management--clear program goals, a well-
defined strategy for achieving those goals, and performance measures
that link to the program goals.[Footnote 24] In response to our
concerns, PHMSA adopted a strategy in August 2005 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 pipeline
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), ensures 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 of 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 by developing comprehensive guidance
tools, training inspectors on their use, and effectively using state
inspection capabilities.
Finally, to understand the 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 issues that threaten the overall framework of integrity
management. We expect to provide additional insights into issues
involving state pipeline agency staffing and training and the 7-year
reassessment requirement 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 shakedown
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.
[2] GAO, Pipeline Safety: Preliminary Information on the Office of
Pipeline Safety's Actions to Strengthen Its Enforcement Program, GAO-04-
985T (Washington, D.C.: July 20, 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 standards, including reassessment standards, developed by
the American Society of Mechanical Engineers: Managing the System
Integrity of Gas Pipelines (ASME B31.8S-2004) and the National
Association of Corrosion Engineers: Standard Recommended Practice -
Pipeline External Corrosion Direct Assessment (NACE RP0502-2002).
[4] For the purpose of this statement, we treat the District of
Columbia as a state pipeline agency.
[5] Operators have reported that about 20,000 miles of pipeline 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. Stress risers are
corrosion, gouges, or cracks within or between dents.
[6] The standards have been accepted by the American National Standards
Institute, a private, non-profit organization whose mission is to
promote and facilitate voluntary consensus standards and promote their
integrity. The Institute does not approve the technical merits of
proposed national standards. Rather it ensures that proposed national
standards are developed in an environment of openness, balance,
consensus, and due process.
[7] 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.
[8] An incident, for PHMSA reporting purposes, involves a death; injury
requiring hospitalization; or property damage, including any loss of
natural gas during an incident, of $50,000 or more.
[9] Confirmatory direct assessment allows for less extensive use of
testing methods and is meant to provide assurance that drastic damage
is not taking place. Confirmatory direct assessment allows an operator
to obtain interim results until it performs a full reassessment.
[10] As discussed earlier, PHMSA's regulations do not provide for the
5- year reassessment interval that are contained in the industry
national consensus standards.
[11] GAO, Pipeline Safety and Security: Improved Workforce Planning and
Communication Needed, GAO-02-785 (Washington, D.C.: Aug. 26, 2002).
[12] Of the 46 state agencies that responded, three state agencies
indicated that PHMSA information was extremely useful, 23 state
agencies said the information was very useful, 9 state agencies said it
was moderately useful, 5 said it was somewhat useful, 1 said it was not
useful, and 5 had no opinion.
[13] Most operators found no or few problems and a handful found more
than 10 problems overall requiring immediate repair. We hope to portray
these results when we report to this Subcommittee and others this fall.
[14] For example, pipeline operators told us that, when they run an in-
line inspection tool through a pipeline, they do 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.
[15] In figure 1, the results for operator Hi12 show a greater number
of problems requiring immediate repair (per 100 miles assessed) because
it has assessed 11 miles and found 2 of these problems. The other two
operators showing the largest number of problems per 100 miles
requiring immediate repair, Lo25 and Lo26, have assessed 77 miles and
370 miles, respectively.
[16] The other 16 operators either (1) have not calculated reassessment
intervals; (2) do not intend to, given the prescriptive federal (7
years) or state (5 years in Texas) reassessment requirements; or (3)
did not supply us information on their reassessment intervals.
[17] As discussed earlier, the development of these standards met the
American National Standards Institute's requirements for openness,
balance, consensus, and due process.
[18] 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
the pipeline so that the operator can mark the pipeline's location
prior to the digging work.
[19] 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.
[20] Direct assessment is a four-step procedure used to identify
corrosion and other pipeline defects. First, operators analyze
information about the physical characteristics of a pipeline, such as
coating, soil moisture, and past leaks. Second, operators use one or
more tools to examine the pipeline through the soil in areas identified
in the first step. Third, operators use the results of the above-ground
examination to dig holes in intervals along the pipeline to examine
suspected pipeline problem areas. Finally, operators integrate and
analyze information gathered during the three previous steps to
determine when additional digging is necessary and how often pipeline
segments should be reassessed.
[21] To prepare for this hearing, we contacted the Inline Inspection
Association, two companies offering in-line inspection services, and
two companies offering direct assessment services.
[22] 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.
[23] 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.
[24] GAO-04-801.
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