Gas Pipeline Safety
Views on Proposed Legislation to Reauthorize Pipeline Safety Provisions Gao ID: GAO-06-1027T August 4, 2006The Pipeline Safety Improvement Act of 2002 established a risk-based program for gas transmission pipelines--termed integrity management--which requires pipeline operators to identify areas where the consequences of a pipeline incident would be the greatest, such as highly populated areas. Operators must assess pipelines in these areas for safety threats (such as corrosion), repair or replace defective segments, and reassess their pipelines at least every 7 years. Under the Pipeline and Hazardous Materials Safety Administration's (PHMSA) regulations, operators must reassess their pipelines for corrosion at least every 7 years and for all safety threats at least every 10, 15, or 20 years. State pipeline safety agencies that assist PHMSA are eligible to receive matching funds up to 50 percent of the cost of their pipeline safety programs. This statement is based on ongoing work for Congress and for others. It focuses on three areas germane to current legislative reauthorization proposals: (1) an overall assessment of the integrity management program, (2) the 7-year reassessment requirement, and (3) provisions to increase state pipeline safety grants. GAO contacted more than 50 pipeline operators and a broad range of stakeholders and surveyed state pipeline agencies. GAO also reviewed PHMSA and industry guidance and reviewed PHMSA pipeline performance data.
While the gas integrity management program is still being implemented, early indications show that the program benefits pipeline safety. For example, the condition of transmission pipelines is improving as operators assess and repair their pipelines. As of December 31, 2005 (latest data available), 33 percent of the pipelines in highly populated or frequently used areas had been assessed and over 2,300 repairs had been completed. In addition, we estimate that up to 68 percent of the population that lives close to natural gas transmission pipelines is located in highly populated areas and is expected to receive additional protection as a result of improved pipeline safety. Furthermore, despite some uncertainty on the part of operators over the program's documentation requirements, operators, gas pipeline industry representatives, state pipeline officials, and safety advocate representatives all agree that the program enhances public safety, citing operators' improved knowledge of the threats to their pipelines as the primary benefit. Although periodic reassessments of pipeline threats are beneficial, the 7-year reassessment requirement appears to be conservative. Through December 2005, 76 percent of the operators (182 of 241) reporting baseline assessment activity to PHMSA reported that their pipelines were in good condition, requiring only minor repairs. Most of the problems found were concentrated in just 7 pipelines. These results are encouraging, since operators are required to assess their riskiest segments first and operators are required to repair defects, making them safer before reassessments begin toward the end of the decade. There have been no deaths or injuries from corrosion related pipeline incidents over the past 5-1/2 years. An alternative approach is to permit pipeline operators to reassess their pipeline segments at intervals based on technical data, risk factors, and engineering analyses. Such an approach is consistent with the overall philosophy of the 2002 act and would meet its safety objectives. Under this approach, operators could reassess their pipelines at intervals longer than 7 years only if operators can adequately demonstrate that corrosion will not become a threat within the chosen time intervals. Otherwise, the reassessment must occur more frequently. As a safeguard to ensure that operators have identified threats facing these pipeline segments and have determined appropriate reassessment intervals, PHMSA and state regulatory agencies are already conducting integrity management inspections of operators. They plan to inspect most operators' integrity management activities by 2009. The provision to increase the cap on pipeline safety grants to states appears reasonable given that states' workloads are expanding, but funding sources and oversight of states' expanded activities would need to be addressed in order to ensure that the increased grants are appropriately carried out. PHMSA has identified several potential funding sources, such as reprioritizing the agency's budget and increasing pipeline user fees. For oversight, PHMSA anticipates integrating states' expanded activities into the agency's current oversight approach that relies on annual reports from states and field evaluations.
GAO-06-1027T, Gas Pipeline Safety: Views on Proposed Legislation to Reauthorize Pipeline Safety Provisions
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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:
Submitted August 4, 2006:
Gas Pipeline Safety:
Views on Proposed Legislation to Reauthorize Pipeline Safety
Provisions:
Statement for the Record by:
Katherine Siggerud, Director Physical Infrastructure Issues:
GAO-06-1027T:
GAO Highlights:
Highlights of GAO-06-1027T, a testimony before the Subcommittee on
Energy and Air Quality, Committee on Energy and Commerce, House of
Representatives
Why GAO Did This Study:
The Pipeline Safety Improvement Act of 2002 established a risk-based
program for gas transmission pipelines”termed integrity
management”which requires pipeline operators to identify areas where
the consequences of a pipeline incident would be the greatest, such as
highly populated areas. Operators must assess pipelines in these areas
for safety threats (such as corrosion), repair or replace defective
segments, and reassess their pipelines at least every 7 years. Under
the Pipeline and Hazardous Materials Safety Administration‘s (PHMSA)
regulations, operators must reassess their pipelines for corrosion at
least every 7 years and for all safety threats at least every 10, 15,
or 20 years. State pipeline safety agencies that assist PHMSA are
eligible to receive matching funds up to 50 percent of the cost of
their pipeline safety programs.
This statement is based on ongoing work for this Subcommittee and for
others. It focuses on three areas germane to current legislative
reauthorization proposals: (1) an overall assessment of the integrity
management program, (2) the 7-year reassessment requirement, and (3)
provisions to increase state pipeline safety grants. GAO contacted more
than 50 pipeline operators and a broad range of stakeholders and
surveyed state pipeline agencies. GAO also reviewed PHMSA and industry
guidance and reviewed PHMSA pipeline performance data.
What GAO Found:
While the gas integrity management program is still being implemented,
early indications show that the program benefits pipeline safety. For
example, the condition of transmission pipelines is improving as
operators assess and repair their pipelines. As of December 31, 2005
(latest data available), 33 percent of the pipelines in highly
populated or frequently used areas had been assessed and over 2,300
repairs had been completed. In addition, we estimate that up to 68
percent of the population that lives close to natural gas transmission
pipelines is located in highly populated areas and is expected to
receive additional protection as a result of improved pipeline safety.
Furthermore, despite some uncertainty on the part of operators over the
program‘s documentation requirements, operators, gas pipeline industry
representatives, state pipeline officials, and safety advocate
representatives all agree that the program enhances public safety,
citing operators‘ improved knowledge of the threats to their pipelines
as the primary benefit.
Although periodic reassessments of pipeline threats are beneficial, the
7-year reassessment requirement appears to be conservative. Through
December 2005, 76 percent of the operators (182 of 241) reporting
baseline assessment activity to PHMSA reported that their pipelines
were in good condition, requiring only minor repairs. Most of the
problems found were concentrated in just 7 pipelines. These results are
encouraging, since operators are required to assess their riskiest
segments first and operators are required to repair defects, making
them safer before reassessments begin toward the end of the decade.
There have been no deaths or injuries from corrosion related pipeline
incidents over the past 5-1/2 years. An alternative approach is to
permit pipeline operators to reassess their pipeline segments at
intervals based on technical data, risk factors, and engineering
analyses. Such an approach is consistent with the overall philosophy of
the 2002 act and would meet its safety objectives. Under this approach,
operators could reassess their pipelines at intervals longer than 7
years only if operators can adequately demonstrate that corrosion will
not become a threat within the chosen time intervals. Otherwise, the
reassessment must occur more frequently. As a safeguard to ensure that
operators have identified threats facing these pipeline segments and
have determined appropriate reassessment intervals, PHMSA and state
regulatory agencies are already conducting integrity management
inspections of operators. They plan to inspect most operators‘
integrity management activities by 2009.
The provision to increase the cap on pipeline safety grants to states
appears reasonable given that states‘ workloads are expanding, but
funding sources and oversight of states‘ expanded activities would need
to be addressed in order to ensure that the increased grants are
appropriately carried out. PHMSA has identified several potential
funding sources, such as reprioritizing the agency‘s budget and
increasing pipeline user fees. For oversight, PHMSA anticipates
integrating states‘ expanded activities into the agency‘s current
oversight approach that relies on annual reports from states and field
evaluations.
[Hyperlink, http://www.gao.gov/cgi-bin/getrpt?GAO-06-1027T].
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 assist the Subcommittee in its efforts
to reauthorize the Pipeline Safety Improvement Act of 2002, which
strengthened federal pipeline safety programs and enforcement, state
oversight of pipeline operators, and public education on pipeline
safety. This statement is based on the preliminary results of our
ongoing work for this Subcommittee and others on aspects of the
integrity management program for gas transmission pipelines established
under the 2002 act.[Footnote 1] We appeared before this subcommittee in
April to discuss these topics.[Footnote 2] This statement focuses on
three areas that are related to the Subcommittee's July 20, 2006, draft
bill; H.R. 5782, as introduced; and the administration's pipeline
reauthorization, introduced as H.R. 5678. These three areas are (1) an
overall assessment of the integrity management program, (2) the 7-year
reassessment requirement, and (3) provisions to increase state pipeline
safety grants.
Our work is based on our review of laws, regulations, pipeline
performance data, and other guidance from the federal regulator--the
Pipeline and Hazardous Materials Safety Administration (PHMSA)--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] We also reviewed industry consensus
standards for maximum reassessment intervals developed by the American
Society of Mechanical Engineers. 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 52 pipeline operators. These operators represent nearly
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 threats.
Because we used a non-probability method of selecting these operators,
we cannot project our findings nationwide.[Footnote 5] 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 July 2006.
In summary:
* While the gas integrity management program is still being
implemented, early indications show that the program benefits pipeline
safety, as intended by Congress. First, the condition of transmission
pipelines is improving as operators complete their first round of
pipeline assessments and make repairs. For example, 33 percent of the
identified pipelines in highly populated or frequently used areas had
been assessed and over 2,300 repairs had been completed as of December
31, 2005 (latest data available). In addition, we estimate that up to
68 percent of the population that lives close to natural gas
transmission pipelines is located in highly populated areas and is
expected to receive additional protection as a result of improved
pipeline safety as operators complete their baseline assessments by
December 2012, as required. Furthermore, despite some uncertainty on
the part of operators over the program's documentation requirements,
operators, gas pipeline industry representatives, state pipeline
officials, and safety advocate representatives all agree that the
program enhances public safety, citing operators' improved knowledge of
the threats to their pipeline systems that stems from systematic
assessments as the primary benefit of the program.
* Regarding the 7-year reassessment requirement, the draft Subcommittee
bill would require the Secretary of Transportation to submit a
legislative proposal after it receives our report on the subject. Our
work, which is nearing completion, concludes that periodic
reassessments are beneficial, but that the 7-year reassessment
requirement appears to be conservative based on a number of factors.
Among these are results of the baseline assessments conducted to date
and the overall safety record of the gas transmission industry. In this
regard, through December 2005, 76 percent of the operators (182 of 241)
reporting baseline assessment activity reported to PHMSA that their
pipelines were in good condition and free of major defects, requiring
only minor repairs. Most of the 340 problems found were concentrated in
just 7 pipelines, although it is not known how many of these problems
were due to corrosion. (These assessments reported by the 241 operators
covered about 6,700 miles, or about one-third of the nationwide total
to be assessed by 2012.) These results are encouraging, since operators
are required to assess their riskiest segments first. Furthermore,
since operators are required to repair these pipelines, the overall
safety and condition of the pipeline system should be improved before
reassessments begin toward the end of the decade. Regarding safety,
PHMSA data show corrosion incidents are relatively rare: over the past
5-1/2 years (from January 2001 through early July 2006), there were 26
corrosion-related incidents over the 295,000-mile transmission system
per year, on average--none of which resulted in death or
injury.[Footnote 6]
* The administration's proposal would require the Secretary of
Transportation to issue regulations basing reassessment intervals on
technical data, risk factors, and engineering analyses. Based on our
nearly completed work, we think that this approach is reasonable and
would achieve the safety objectives of the 2002 act. It is also
consistent with the overall philosophy of the integrity management
legislation passed by the Congress in 2002. As discussed later in this
statement, if PHMSA incorporates existing industry consensus standards
for corrosion into its regulations, operators would be allowed to
reassess their pipelines for time-dependent threats at least every 10,
15, or 20 years only if the operator can adequately demonstrate that
corrosion will not become a threat within the chosen time interval. If
not, then the reassessment must occur more frequently, perhaps at 7 or
even fewer years. As a safeguard for ensuring that operators have
identified threats facing pipeline segments and have determined
appropriate reassessment intervals, PHMSA and state regulatory agencies
are already conducting inspections. They plan to inspect most
operators' integrity management activities by 2009.
* The provision in the Subcommittee's draft bill to increase the cap on
pipeline safety grants to states from 50 percent to 80 percent of the
cost of their expanded pipeline safety programs appears reasonable
given that states' workload is increasing to, among other activities,
enforce integrity management requirements and damage prevention
programs. However, if Congress approves this provision, two areas would
need to be addressed to ensure that the increased grants are
appropriately carried out: the source of funding for the increased
grant amounts and oversight of the expanded state pipeline safety
activities. According to PHMSA, the agency has identified funding
options--including reprioritizing the agency's budget to channel funds
from other activities (such as research) and increasing user fees
charged to pipeline companies --but has not developed a specific plan
for how to provide additional funds to states. PHMSA currently oversees
state pipeline safety activities through annual reports from the states
and field evaluations. According to PHMSA officials, expanded state
pipeline safety agency activities would be included in PHMSA's
oversight approach.
Background:
The United States has a 295,000-mile network of natural gas
transmission pipelines that are owned and operated by approximately 900
operators. These pipelines are important to the nation because they
transport nearly all the natural gas used, which provides about a
quarter of the nation's energy supply. Gas transmission pipelines
typically move gas products over long distances from sources to
communities and are primarily interstate. They generally deliver
natural gas to local distribution pipelines, which distribute the gas
to commercial and residential end-users. Local distribution companies
may also operate small portions of transmission pipelines.
PHMSA administers the national regulatory program to ensure the safe
transportation of natural gas and hazardous liquid by pipeline. In
general, PHMSA retains full responsibility for inspecting and enforcing
regulations on interstate pipelines, but it has arrangements with 48
states, the District of Columbia, and Puerto Rico to assist with
overseeing intrastate pipelines. These states are currently authorized
to receive reimbursement of up to 50 percent of the costs of their
pipeline safety programs from PHMSA.
Traditionally, PHMSA has carried out its oversight role using minimum
safety standards that were uniformly applied to all pipelines based on
the "class location" of the pipeline. A pipeline's class location--
based on factors such as population within 660 feet of the pipeline--
determines the applicable standards such as the thickness of the pipe
required and the pressure at which it can operate. The Pipeline Safety
Improvement Act of 2002 modified PHMSA's traditional oversight approach
by supplementing the minimum standards with a risk-based program for
gas transmission pipelines. This program--termed "integrity
management"--requires gas transmission pipeline operators to assess and
mitigate safety threats, such as leaks or ruptures due to incorrect
operation or corrosion, to pipeline segments that are located in highly
populated or frequently used areas, such as parks. Specifically,
operators are required to perform baseline assessments on half of the
pipeline mileage located in these areas by December 2007, and the
remainder by December 2012. Those pipeline segments potentially facing
the greatest risks of failure from leaks or ruptures are to be assessed
first. As of December 2005 (latest data available), 447 gas pipeline
operators reported to PHMSA that about 20,000 miles of their pipelines
(about 7 percent of all gas transmission pipeline miles) lie in highly
populated or frequently used areas. Individual operators reported that
they have as many as about 1,600 miles and as few as 0.02 miles of
pipeline in these areas.
The 2002 act also requires that operators reassess these pipeline
segments for safety threats at least every 7 years. Under flexibility
provided by the act, PHMSA requires that operators reassess these
pipeline segments for corrosion damage at least every 7 years in its
implementing regulations, because corrosion is the most frequent cause
of failures that can occur over time.[Footnote 7] (See fig. 1.) PHMSA's
regulations also incorporated, as mandatory, voluntary industry
consensus standards on maximum reassessment intervals into these
regulations for other types of safety threats. The industry standards
require that operators reassess gas pipelines at least every 10, 15, or
20 years for all safety threats depending primarily on the condition of
the pipelines and the pressure under which they operate. If conditions
warrant, reassessments must occur more frequently. In addition,
operators must perform prevention and mitigation activities--such as
monitoring their pipelines for excavation or corrosion damage--on a
continuing basis.
Figure 1: Reassessments Every 7 Years for Corrosion Supplement Broader
Periodic Reassessments:
[See PDF for image]
Source: GAO.
Note: Periodic reassessments occur at least every 10, 15, or 20 years.
Both periodic and 7-year reassessments are supposed to occur more
frequently if conditions warrant.
[End of figure]
Gas Integrity Management Program Benefits Pipeline Safety:
Operators are making good progress in assessing and repairing their
pipelines, thereby improving the safety of their pipeline systems. As
of December 2005, operators had assessed about 6,700 miles of their
20,000 miles--or about 33 percent--of pipelines located in highly
populated or frequently used areas. This progress indicates that they
are well on their way to meeting the requirement to conduct baseline
assessments on 50 percent of their pipelines in these areas by December
2007. In addition to assessing their pipelines, operators are also
making progress in fulfilling the requirement to repair problems found
on their pipelines in highly populated or frequently used areas. In the
2 years that operators have reported the results of integrity
management, they have completed 340 repairs that were immediately
required and another 1,981 scheduled repairs in highly populated or
frequently used areas.[Footnote 8] 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. Furthermore, the benefits of integrity
management expand beyond highly populated or frequently used areas
because a large number of operators are using internal inspection tools
to assess their pipelines. These tools must be inserted and removed
from the pipelines at designated locations that often run through other
areas. Consequently, operators reported having assessed about 44,000
miles of pipelines located outside highly populated or frequently used
areas, representing about 15 percent of all gas transmission pipelines.
While operators are not required to report to PHMSA the results of
these expanded assessments, operators we spoke with said that they plan
to make necessary repairs identified through the assessments regardless
of where they are identified.
We estimate that the integrity management program should offer
additional safety benefits over the minimum safety standards for up to
68 percent of the population living close to gas transmission
pipelines. This estimate corresponds with PHMSA's estimate of two-
thirds of the population.
A number of representatives from pipeline industry organizations, state
pipeline agencies, safety advocate groups, and operators that we
contacted agree that integrity management benefits public safety
because it requires all operators to systematically assess their
pipelines to gain a comprehensive knowledge about the risks to their
pipeline systems. Other benefits cited by operators include improved
communications within their companies and more strategic resource
allocation.
While the operators we contacted generally believe integrity management
is beneficial, the program is not without its costs. For example, over
half of the operators we spoke with said that they have hired
additional staff or contractors as a result of the integrity management
requirements. In addition, 19 of the operators we contacted (37
percent) were concerned 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. The regulations provide operators the flexibility to develop
their programs to best suit their companies' needs, but each operator
must develop and document specific policies and procedures to
demonstrate its commitment to compliance with and implementation of the
integrity management program. Operators may use existing policies and
procedures if they meet the requirements of integrity management. In
addition, an operator must document any decisions made related to
integrity management to demonstrate that it understands the threats to
their pipelines and is systematically managing their pipelines for
these threats. While the operators we contacted generally 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.
In addition, a few operators expressed concern that they will not know
if they have sufficient documentation until their programs have been
inspected. Initial inspections of operators by PHMSA and state pipeline
agencies have confirmed that some operators are experiencing difficulty
with documentation but are generally doing well with assessments and
repairs. According to PHMSA and state officials, as operators continue
to develop and implement their integrity management programs and as
they are provided feedback during inspections, the documentation issues
identified during these initial inspections should be resolved.
Another concern raised by 33 (65 percent) of the operators is the
requirement to reassess their pipelines for corrosion problems at least
every 7 years. This issue is discussed in the following section.
The 7-year Reassessment Requirement Appears to be Conservative:
Periodic reassessments of pipeline threats are beneficial because
threats--such as the corrosive nature of the gas being transported--can
change over time. However, the findings from baseline assessments
conducted to date and the generally safe condition of gas transmission
pipelines leads us to conclude that the 7-year requirement appears to
be conservative. Through December 2005 (latest data available), 76
percent of the operators (182 of 241) reporting baseline assessment
activity to PHMSA told the agency that their pipelines were in good
condition, free of major defects, and requiring only minor
repairs.[Footnote 9] (See fig. 2.) The remaining 59 operators found 340
problems requiring immediate repairs. About 60 percent of these
problems occurred in seven operators' pipelines. Since PHMSA does not
require that operators tell it the nature of the problems found, we do
not know how many, if any, were due to corrosion. These assessments
covered about 6,700 miles, or about one-third of the nationwide total
to be assessed.[Footnote 10]
Figure 2: Most Operators Reported That Their Pipelines Are In Good
Condition, as of December 2005:
[See PDF for image]
Source: GAO presentation of PHMSA data.
Note: Results of 241 operators that reported to PHMSA that they
completed 6,700 miles of baseline assessments. Of those operators that
reported no problems, 82 operate smaller pipeline systems (1-49 miles),
41 operate mid-sized pipeline systems (50-199 miles), and 59 operate
larger pipeline systems (200 or more miles).
[End of figure]
It is encouraging that the majority of operators nationwide reported
that they found few or no problems requiring immediate repairs, because
operators are supposed to assess pipeline segments facing the greatest
risk of failure from leaks or ruptures first, as required by the 2002
act. In addition, since operators are required to identify and repair
significant problems, the overall safety and condition of the pipeline
system should be enhanced before reassessments begin toward the end of
the decade.
Regarding the industry's overall safety record, over the past 5-1/2
years (from January 2001 through early July 2006), there were 143
corrosion-related incidents over the 295,000-mile transmission system
(26 per year, on average)--none of which resulted in death or injury.
Over the past 10-1/2 years, 12 people have died and 3 have been injured
in two corrosion-related incidents.[Footnote 11] Neither of these
incidents occurred in a highly populated or frequently used area.
About 80 percent of the 52 operators that we contacted prefer that
reassessment intervals be based on the condition and characteristics of
the pipeline segment rather than on a prescriptive standard. About half
of these operators (28) expressed a preference for the industry
consensus standard developed by the American Society of Mechanical
Engineers (ASME B31.8S-2004) for setting reassessment intervals for
time-dependent threats because it incorporates a risk-based approach
(for pipeline failure) and is based on science and engineering
knowledge. This standard sets reassessment intervals at a maximum of 10
years for high-stress pipeline segments, 15 years for medium-stress
segments, and 20 years for low-stress segments.[Footnote 12] Maximum
reassessment intervals, such as those in the industry consensus
standard, incorporate such risk concepts as built-in safety factors
(e.g., wall stress, test pressure, or predicted failure), conditions,
and potential consequences of a pipeline incident on a segment-by-
segment basis. The maximum intervals of 10, 15, and 20 years are based
on worst-case corrosion growth rates.
Industry consensus standards allow for maximum reassessment intervals
for time-dependent threats of 10, 15, or 20 years only if the operator
can adequately demonstrate that corrosion will not become a threat
within the chosen time interval. If not, then the reassessment must
occur sooner, perhaps at 7 or even 5 or fewer years. Furthermore,
according to industry consensus standards, it typically takes longer
than the 10, 15, or 20 years specified in the standard for corrosion
problems to result in a leak or rupture.
The industry consensus standards were developed in 2001 and updated in
2004 based on, among other things, the experience and expertise of
engineers, contractors, operators, local distribution companies, and
pipeline manufacturers; more than 20 technical studies conducted by the
Gas Technology Institute, ranging from pipeline design factors to
natural gas pipeline risk management; and other industry consensus
standards including the National Association of Corrosion Engineers
standards, on topics such as corrosion. Contributors have been
practicing aspects of risk-based assessments successfully for over 10
years. The ASME standard serves as a foundation for nearly every
section of PHMSA's integrity management regulations. The ASME standard
was reviewed by the American National Standards Institute.[Footnote 13]
The Institute found that the standard was developed in an environment
of openness, balance, consensus, and due process and therefore approved
it as an American National Standard.
While the mechanical engineering standards are voluntary for the
industry, PHMSA incorporated them as mandatory in its gas transmission
integrity management regulations. The mechanical engineering society's
standard for setting reassessment intervals is not the only industry
consensus standard in PHMSA's integrity management regulations. The
regulations incorporate other industry consensus standards for
assessing corrosion threats and for determining temporary reductions in
operating pressure. In addition, it is federal policy to encourage the
use of industry consensus standards: Congress expressed a preference
for technical standards developed by consensus bodies over agency-
unique standards in the National Technology Transfer and Advancement
Act of 1995. The Office of Management and Budget's Circular A-119
provides guidance to federal agencies on the use of voluntary consensus
standards, including the attributes that define such standards.
Of the 52 operators we contacted, 44 had undertaken baseline
assessments, and 23 of these have calculated their own reassessment
intervals.[Footnote 14] Twenty of these 23 operators indicated that,
based on the conditions they identified during their baseline
assessments, they would reassess their pipelines at maximum intervals
of 10, 15, or 20 years--as allowed by industry consensus standards--if
the 7-year reassessment requirement were not in place. The remaining
three operators told us that they would reassess their pipelines at
intervals shorter than the industry consensus standards but longer than
7 years because of the condition of their pipelines. These results add
weight to our assessment that the 7-year requirement appears to be
conservative for most pipelines.
Safeguards Exist if an Alternative Standard for Corrosion Reassessments
is Allowed:
PHMSA and the state pipeline agencies plan to inspect all operators'
compliance with integrity management reassessment requirements, among
other things, to ensure that operators continually and appropriately
assess the conditions of their pipeline segments in highly populated or
frequently used areas. These inspections should serve as a check as to
whether operators have identified threats facing these pipeline
segments and determined appropriate reassessment intervals. PHMSA and
states have begun inspections and expect to complete most of the first
round of inspections no later than 2009. As of June 2006, PHMSA has
completed 20 of about 100 inspections and, as of January 2006, states
have begun or completed about 117 of about 670 inspections. Initial
results from these inspections show that operators are doing well in
assessing their pipelines and making repairs, but, as discussed
earlier, some need to better document their programs. Based on the
initial inspection results to date, PHMSA and states did not find many
issues that warranted enforcement actions.
Finally, it is important to note that, in addition to periodic
reassessments, operators must perform prevention and mitigation
activities on a continuing basis. PHMSA regulations require that all
operators of pipelines, including those outside highly populated or
frequently used areas, patrol their pipelines for excavation and other
damage, survey for leakage, maintain valves, ensure that corrosion-
preventing protections are working properly, and take other prevention
and mitigation measures.
(Attachment I summarizes results of our work to date on the expected
availability of resources for pipeline reassessments and the likely
impact of assessment activity (including reassessments) on the nation's
natural gas supply. We will discuss these topics in more detail in when
we report on the 7-year reassessment requirement this fall.)
Increasing State Funding Appears Reasonable, but Funding Sources and
Oversight Plans Would Need To Be Addressed:
The Subcommittee's draft bill proposes to increase the matching funds
that PHMSA provides to states for pipeline safety program activities
from a maximum of 50 percent to a maximum of 80 percent of a state's
pipeline safety program costs. The increased funding would offset
states' increased workload, such as activities related to gas
transmission integrity management and other provisions in the 2002 act.
All three legislative proposals also contain provisions, such as damage
prevention programs, that could increase states' workloads.
Furthermore, state pipeline safety activities would increase if PHMSA
implements its planned integrity management program for distribution
pipelines. Our recent survey to state pipeline safety agencies about
their integrity management oversight programs showed that 39 of 47
state agencies are experiencing challenges in staffing, which could
require increased funding. For example, two state officials told us
that state agencies are losing trained inspectors because the state
salaries are typically lower than what operators pay. PHMSA proposes to
implement the increased funding in 5 percent increments over a 6-year
period starting in fiscal year 2008.
We believe that the proposed increase in state grants to offset
expanded state activities appears reasonable, provided that appropriate
funding sources are identified and that the activities are included in
PHMSA's oversight of state pipeline safety programs. According to
PHMSA, the agency has several options for increasing funding for state
grants, but has not developed a specific plan for how to provide
additional funds. One option is for PHMSA to reprioritize its budget to
channel additional funds from other activities, such as research, to
states. Another option may be to increase user fees that are charged to
pipeline companies. User fee assessments in fiscal year 2006 were about
$150 per pipeline mile for natural gas transmission operators and about
$76 per pipeline mile for hazardous liquid pipelines. All of these
options involve tradeoffs among PHMSA's pipeline safety oversight
activities or could result in increased fees from the pipeline
industry. Therefore, the effects of these options would need to be
carefully analyzed in order to find a balanced solution.
According to PHMSA, the agency plans to monitor increased state
pipeline safety activities through its current oversight approach,
which consists of reviewing annual reports from states and field
evaluations of state activities. States are required to submit
documentation annually about their pipeline safety program activities
for the previous year, including information on the state's pipeline
operators, inspections conducted, and enforcement of pipeline
regulations. States are also required to submit a description of all
ongoing and planned activities and an estimate of the total expenses
for the next calendar year. PHMSA validates the information submitted
by each state and attends at least one state inspection during field
evaluations. As state pipeline safety activities expand, PHMSA would
need to determine the best approach for including the new activities in
its oversight of state pipeline safety programs.
Concluding Observations:
The overall integrity management framework laid out in the Pipeline
Safety Improvement Act is improving the safety of gas transmission
pipelines. We have not identified issues that bring into question the
basic framework of integrity management. Overall, we believe that PHMSA
has done a good job in implementing the act. While we expect to make
several recommendations to PHMSA when we complete our work, they will
be aimed at incremental improvements, rather than major restructuring.
Finally, regarding the 7-year reassessment requirement, our preliminary
view is that these reassessment intervals should be based on technical
data, risk factors, and engineering analyses rather than a prescribed
term. We expect to make a recommendation to the Congress that the 2002
act be amended along these lines when we report on this issue. We
expect to report to this Subcommittee and to other committees both on
PHMSA's implementation of integrity management and the 7-year
reassessment requirement in September.
GAO Contact and Staff Acknowledgements:
For further information on this statement, please contact Katherine
Siggerud at (202) 512-2834 or siggerudk@gao.gov. Individuals making key
contributions to this statement were Jennifer Clayborne, Anne Dilger,
Seth Dykes, Maria Edelstein, Heather Frevert, Bert Japikse, Timothy
Guinane, Matthew LaTour, James Ratzenberger, and Sara Vermillion.
[End of section]
Appendix: Availability of Resources to Conduct Reassessments and
Possible Impacts on the Nation's Natural Gas Supply:
This appendix summarizes results of our work to date on the expected
availability of resources for pipeline reassessments and the likely
impact of assessment activity (including reassessments) on the nation's
natural gas supply.
Sufficient Resources May Be Available for Pipeline Reassessments:
Sufficient resources may be available for operators to reassess their
pipelines, but some uncertainty exists. Thirty-seven of the 52
operators, an in-line inspection association and four inspection
contractors that we contacted told us that services and tools needed to
conduct assessments will likely be available for baseline assessments
and they do not anticipate difficulties obtaining these resources in
the future. Operators that reported both baseline and reassessment
schedules told us they plan to reassess 42 percent of their pipeline
miles in highly populated or frequently used areas using in-line
inspection.[Footnote 15] An in-line inspection association and two
contractors we contacted said that the in-line inspection industry is
well established and has the capacity to expand readily. Operators plan
to use direct assessment or confirmatory direct assessment methods in
reassessing another 54 percent of their pipeline miles.[Footnote 16]
However, they told us that expertise for direct assessment methods is
limited; therefore, they may not be as readily available to all
operators.
The Interstate Natural Gas Association of America (INGAA), the American
Gas Association (AGA) and we asked operators to estimate the number of
miles of pipeline they planned to assess through 2012 in order to
determine whether an increase in overall assessment activity would
occur because of the overlap between completing baseline assessments
and beginning reassessments from 2010 through 2012. The results were
conflicting: the industry effort showed an increase in activity, while
ours showed a decrease. (See fig. 3.) The reasons for these contrasting
findings are unclear but may be due, in part, to the difference in
methods used in collecting this information.
Figure 3: GAO and INGAA/AGA Results Show Different Trends in their
Required Assessment Activity During the Overlap Period:
[See PDF for image]
Source: GAO discussions with 52 operators and GAO analysis of INGAA/AGA
results.
[End of figure]
Impact of Periodic Reassessments on Natural Gas Supply May be Less than
Foreseen:
As the Pipeline Safety Improvement Act of 2002 was being considered,
INGAA analyzed the possible impact of requiring assessments and
periodic reassessments and found that significant disruptions in the
natural gas supply and considerable price increases could
occur.[Footnote 17] A more moderate impact was predicted in three
subsequent analyses--two reviews of the INGAA study performed for PHMSA
by the John A. Volpe National Transportation Systems Center and by the
Department of Energy during the congressional debate over the pipeline
bill, and a post-act PHMSA evaluation of its implementing
regulations.[Footnote 18] A waiver provision was included in the 2002
act after INGAA's study was completed; this may serve as a safety valve
if it appears that the natural gas supply may be disrupted. Finally, of
the 44 natural gas pipeline operators that we contacted that had begun
baseline assessments,[Footnote 19] 26 operators (59 percent) indicated
that their assessments and repairs did not require them to shutdown
their pipelines or reduce their operating pressure. Sixteen (36
percent) reported minor disruptions in their gas supply because they
temporarily shut down pipelines and reduced operating pressure to
conduct assessments or repairs. They told us that they used alternate
gas sources, such as liquefied natural gas, to sustain their customers'
gas supply. The remaining two operators told us that they were not able
to meet all their customers' needs, but the customers were able to
obtain natural gas from other sources.
FOOTNOTES
[1] Under integrity management, operators are required to develop
programs to systematically assess and mitigate safety threats, such as
leaks or ruptures, for the portions of their pipelines that are in
highly populated or frequently used areas (such as parks). They must
complete baseline assessments by 2012 and then reassess these pipeline
segments every 7 years. Under PHMSA's regulations, operators must
reassess their pipelines for corrosion at least every 7 years and for
all time-dependent safety threats at least every 10, 15, or 20 years.
Transmission pipelines transport gas products from sources to
communities and are primarily interstate.
[2] GAO, Gas Pipeline Safety: Preliminary Observations on the
Implementation of the Integrity Management Program, GAO-06-588T
(Washington, D.C.: April 27, 2006).
[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.
[4] For the purpose of this statement, we treat the District of
Columbia as a state pipeline agency.
[5] Results from nonprobability samples cannot be used to make
inferences about a population because, in a nonprobability sample, some
elements of the population being studied have no chance or have an
unknown chance of being selected as part of the sample.
[6] There have been two corrosion-related incidents in the last 10-1/2
years that have resulted in a death or injury. Neither occurred in a
highly populated or frequently used area.
[7] Other types of failures are independent of time, such as damage
from cold weather, land movement, or incorrect operation.
[8] A repair must be made immediately when specific conditions are
identified related to the strength of a pipeline such as, a dent with
an indication of metal loss or cracking, or an anomaly judged to
require immediate action. Scheduled repairs must be made within 1 year
and generally include conditions where a dent has been identified but
there is no indication of metal loss.
[9] We contacted 52 operators about the results of their baseline
assessments, and the results were largely consistent with the overall
data reported to PHMSA.
[10] Another way to assess progress in completing baseline assessments
and the effect of problems found would be to measure gas flows or
pipeline capacity in those areas. This information is not readily
available.
[11] All the fatalities and all but one of the injuries occurred in one
incident. Over the same period, an average of 3 people have died and 8
people have been injured per year from all causes of natural gas
transmission pipeline incidents.
[12] Stress is measured in terms of operating pressure in relation to
wall strength.
[13] The American National Standards Institute is 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.
[14] The other 21 operators either (1) have not yet calculated
reassessment intervals; (2) do not intend to, given prescriptive
federal (7 years) or state (5 years in Texas) reassessment
requirements; or (3) did not supply us with information on their
reassessment intervals.
[15] In-line inspection involves running a specialized tool through a
pipeline to detect and record anomalies, such as metal loss and damage.
[16] Direct assessment and confirmatory direct assessment involve using
above-ground detection instruments, and then excavating suspected
problem areas.
[17] Prepared for The INGAA Foundation, Inc., by Energy and
Environmental Analysis, Inc., Consumer Effects of the Anticipated
Integrity Rule for High Consequence Areas, 2002.
[18] See, Department of Transportation docket, RSPA-00-7666, Energy
Impact Statement for Pipeline Integrity Management in High Consequence
Areas (Gas Transmission Pipelines), March 28, 2002, prepared by John A.
Volpe National Transportation Systems Center and the U.S. Department of
Transportation; Comments from U.S. Department of Energy on INGAA's
Consumer Effects of the Anticipated Integrity Rule for High Consequence
Areas, April 2, 2002; and Research and Special Programs Administration,
Final Regulatory Evaluation, Pipeline Integrity Management in High
Consequence Areas (Gas Transmission Pipelines), March 28, 2002.
[19] Fifty of the 52 operators that we contacted operate natural gas
pipeline and six have not yet begun baseline assessment activities.
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