Natural Gas Pipeline Safety
Integrity Management Benefits Public Safety, but Consistency of Performance Measures Should be Improved Gao ID: GAO-06-946 September 8, 2006The Pipeline Safety Improvement Act of 2002 established a risk-based program for gas transmission pipelines--the integrity management program. The program requires operators of natural and other gas transmission pipelines to identify "high consequence areas" where pipeline incidents would most severely affect public safety, such as those occurring in highly populated or frequented areas. Operators must assess pipelines in these areas for safety risks and repair or replace any defective segments. Operators must also submit data on performance measures to the Pipeline and Hazardous Materials Safety Administration (PHMSA). The 2002 act also directed GAO to assess this program's effects on public safety. Accordingly, we examined (1) the effect on public safety of the integrity management program and (2) PHMSA and state pipeline agencies' plans to oversee operators' implementation of program requirements. To fulfill these objectives, GAO interviewed 51 gas pipeline operators and surveyed all state pipeline agencies.
The gas integrity management program is designed to benefit public safety by supplementing existing safety requirements with risk-based management principles that focus on safety risks in high consequence areas, such as highly populated or frequented areas. Early indications show that the condition of transmission pipelines is improving as operators complete assessments and related repairs of their pipelines. For example, as of December 31, 2005, operators had assessed 33 percent of pipelines in high consequence areas and completed over 2,000 repairs. Furthermore, up to 68 percent of the population living near gas transmission pipelines is expected to benefit from improved pipeline safety because they live in highly populated areas. Representatives from the pipeline industry, safety advocacy groups, and state pipeline safety agencies generally agree that integrity management improves public safety, but operators noted that the program can be costly to implement and cited concerns with implementing the program, such as meeting the documentation requirements. PHMSA's performance measures should demonstrate the impact of the program over time. However, we are recommending revisions to improve the measures. For example, adjusting the incident reporting requirement to account for changes in the price of natural gas would allow PHMSA to more accurately track trends in pipeline incidents. PHMSA and states plan to use a variety of inspection tools to oversee operators' implementation of integrity management requirements and expect to complete the first round of inspections no later than 2009. To assist in conducting these inspections, PHMSA has developed a range of tools, including guidance documents and training courses for inspectors. Overall, state agencies have found these tools to be useful, although some states have found it difficult to schedule the required training courses and have some concerns about the adequacy of their staffing. To address these concerns, PHMSA is taking steps to make it easier for state inspectors to attend the training and supports providing additional funding to states. Initial results from 20 federal inspections and 117 state inspections show that operators are making good progress in assessing pipelines and making repairs, but they generally need to better document their decisions and processes.
RecommendationsOur recommendations from this work are listed below with a Contact for more information. Status will change from "In process" to "Open," "Closed - implemented," or "Closed - not implemented" based on our follow up work.
Director: Team: Phone:GAO-06-946, Natural Gas Pipeline Safety: Integrity Management Benefits Public Safety, but Consistency of Performance Measures Should be Improved
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Report to Congressional Committees:
September 2006:
Natural Gas Pipeline Safety:
Integrity Management Benefits Public Safety, but Consistency of
Performance Measures Should Be Improved:
GAO-06-946:
GAO Highlights:
Highlights of GAO-06-946, a report to congressional committees
Why GAO Did This Study:
The Pipeline Safety Improvement Act of 2002 established a risk-based
program for gas transmission pipelines”the integrity management
program. The program requires operators of natural and other gas
transmission pipelines to identify ’high consequence areas“ where
pipeline incidents would most severely affect public safety, such as
those occurring in highly populated or frequented areas. Operators must
assess pipelines in these areas for safety risks and repair or replace
any defective segments. Operators must also submit data on performance
measures to the Pipeline and Hazardous Materials Safety Administration
(PHMSA).
The 2002 act also directed GAO to assess this program‘s effects on
public safety. Accordingly, we examined (1) the effect on public safety
of the integrity management program and (2) PHMSA and state pipeline
agencies‘ plans to oversee operators‘ implementation of program
requirements. To fulfill these objectives, GAO interviewed 51 gas
pipeline operators and surveyed all state pipeline agencies.
What GAO Found:
The gas integrity management program is designed to benefit public
safety by supplementing existing safety requirements with risk-based
management principles that focus on safety risks in high consequence
areas, such as highly populated or frequented areas. Early indications
show that the condition of transmission pipelines is improving as
operators complete assessments and related repairs of their pipelines.
For example, as of December 31, 2005, operators had assessed 33 percent
of pipelines in high consequence areas and completed over 2,000
repairs. Furthermore, up to 68 percent of the population living near
gas transmission pipelines is expected to benefit from improved
pipeline safety because they live in highly populated areas.
Representatives from the pipeline industry, safety advocacy groups, and
state pipeline safety agencies generally agree that integrity
management improves public safety, but operators noted that the program
can be costly to implement and cited concerns with implementing the
program, such as meeting the documentation requirements. PHMSA‘s
performance measures should demonstrate the impact of the program over
time. However, we are recommending revisions to improve the measures.
For example, adjusting the incident reporting requirement to account
for changes in the price of natural gas would allow PHMSA to more
accurately track trends in pipeline incidents.
PHMSA and states plan to use a variety of inspection tools to oversee
operators‘ implementation of integrity management requirements and
expect to complete the first round of inspections no later than 2009.
To assist in conducting these inspections, PHMSA has developed a range
of tools, including guidance documents and training courses for
inspectors. Overall, state agencies have found these tools to be
useful, although some states have found it difficult to schedule the
required training courses and have some concerns about the adequacy of
their staffing. To address these concerns, PHMSA is taking steps to
make it easier for state inspectors to attend the training and supports
providing additional funding to states. Initial results from 20 federal
inspections and 117 state inspections show that operators are making
good progress in assessing pipelines and making repairs, but they
generally need to better document their decisions and processes.
Figure: Integrity Management Process for Gas Transmission Pipelines:
[See PDF for Image]
Source: GAO.
[End of Figure]
What GAO Recommends:
GAO recommends revisions to PHMSA‘s performance measures to improve the
agency‘s ability to determine the impact of the program over time. The
Department of Transportation generally agreed with the report‘s
findings and recommendations.
[Hyperlink, http://www.gao.gov/cgi-bin/getrpt?GAO-06-946].
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]
Contents:
Letter:
Results in Brief:
Background:
Gas Integrity Management Benefits Public Safety, although Operators
Have Some Implementation Concerns, and Performance Measures Could Be
Improved:
PHMSA and State Pipeline Agencies Plan to Use Inspection Tools
Developed by PHMSA to Complete the Initial Round of Inspections by
2009:
Conclusions:
Recommendations for Executive Action:
Agency Comments and Our Evaluation:
Appendixes:
Appendix I: Scope and Methodology:
Appendix II: Results of State Pipeline Agency Survey:
Appendix III: Contact and Staff Acknowledgments:
Table:
Table 1: Integrity Management Performance Measures Reported by
Operators as of December 31, 2005:
Figures:
Figure 1: Gas Pipeline System:
Figure 2: Integrity Management Process for Gas Transmission Pipelines:
Figure 3: Highly Populated Areas within 660 Feet of a Natural Gas
Transmission Pipeline:
Abbreviations:
DOT: Department of Transportation:
IMP: gas integrity management program:
OPS: Office of Pipeline Safety:
PHMSA: Pipeline and Hazardous Materials Safety Administration:
September 8, 2006:
Congressional Committees:
While pipelines are a relatively safe mode for transporting natural
gas, on average, about three people have died and about eight people
have been injured annually over the past 10 years in natural gas
transmission pipeline incidents. To enhance the safety of pipelines and
strengthen existing federal pipeline safety oversight by the Pipeline
and Hazardous Materials Safety Administration (PHMSA), Congress passed
the Pipeline Safety Improvement Act of 2002. A key element of the act
is a risk-based program--termed "integrity management"--for gas
transmission pipelines. The integrity management program requires gas
transmission pipeline operators (operators) to develop programs to
assess and mitigate safety threats to sections of their pipeline
systems where leaks or ruptures would have the greatest impact on
public safety. These "high consequence areas" are generally in highly
populated or frequently used areas, such as parks. Operators must
identify their pipelines in high consequence areas and then
systematically assess these pipelines for safety risks, such as
internal corrosion, and repair or replace any defective pipeline
sections. Operators must also take additional measures, such as
computer monitoring of the pipeline and additional training on response
procedures, to prevent and mitigate the consequences of a pipeline
failure in high consequence areas.
The Pipeline Safety Improvement Act of 2002 directed us to assess the
effects on public safety stemming from the integrity management program
for gas transmission pipelines. Accordingly, we examined (1) the effect
on public safety of the integrity management requirements for gas
transmission pipelines and (2) the plans of PHMSA and state pipeline
safety agencies to oversee operators' implementation of integrity
management requirements.
To carry out this work, we reviewed laws, regulations, and PHMSA
guidance and inspection reports related to the gas integrity management
program. We interviewed agency officials responsible for developing and
administering the gas integrity management program, gas pipeline trade
associations, pipeline safety advocacy groups, state pipeline agencies,
and 51 gas transmission pipeline operators.[Footnote 1] The information
that we obtained from the operators is not generalizable to all
operators. We also surveyed the 47 state pipeline agencies with
responsibility for overseeing gas transmission pipeline operators'
implementation of integrity management.[Footnote 2] As part of our
work, we assessed the internal controls and the reliability of the data
needed for this engagement and determined that the data were
sufficiently reliable for our purposes. We performed our work between
August 2005 and July 2006 in accordance with generally accepted
government auditing standards. (See app. I for additional details on
our scope and methodology and app. II for a copy of our survey sent to
state pipeline agencies and the aggregated results.)
Results in Brief:
The gas integrity management program is benefiting public safety by
supplementing existing safety requirements with risk-based management
principles that focus on safety risks in highly populated or frequented
areas, referred to as high consequence areas. While the program is
still being implemented, the condition of transmission pipelines is
improving as operators complete their first round of pipeline
assessments and make repairs. As a result of integrity management, 33
percent of the identified pipelines in high consequence areas had been
assessed and over 2,000 repairs had been completed, as of December 31,
2005. Furthermore, 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. Gas pipeline
industry, state pipeline agency, and safety advocate representatives
generally agree that the program enhances public safety, citing
operators' improved knowledge of the risks to their pipeline systems
that stems from systematic assessments as the primary benefit of the
program. However, operators noted that integrity management is not
without its costs; most operators we contacted have hired additional
staff or contractors as a result of integrity management requirements.
Furthermore, operators cited concerns about implementing the program,
such as meeting the program's documentation requirements. Despite these
concerns, operators are making good progress in assessing and repairing
their pipeline systems, as demonstrated by the semiannual performance
measures that operators report to PHMSA. However, how the performance
measures are reported may hinder PHMSA's ability to determine the
program's impact over time. For example, incident reporting
requirements do not include an adjustment for changes in the price of
natural gas, even though the value of gas released is a key factor in
determining whether an incident should be reported to PHMSA. Therefore,
a change in the number of incidents reported over time may reflect a
change in the price of natural gas rather than a change in the safety
of the pipeline system. We are making recommendations to improve the
performance measures, thereby improving PHMSA's ability to assess the
effectiveness of the integrity management program.
PHMSA and states plan to use a variety of inspection tools to oversee
operators' implementation of integrity management requirements and
expect to complete the first round of inspections no later than 2009.
PHMSA developed a range of tools to help prepare and assist federal and
state inspectors in conducting integrity management inspections,
including guidance documents for evaluating operators' integrity
management programs, training courses to provide inspectors with a
knowledge of technical issues, and communication mechanisms. Overall,
state agencies have found these tools to be useful, although several
states have found it difficult to schedule the required training
courses, and many have expressed concerns about the adequacy of their
staffing. To address these concerns, PHMSA has taken steps to make it
easier for state inspectors to attend the training, and it supports
providing additional funding to states that could be used for staffing
needs. PHMSA and states have begun inspections. According to PHMSA and
state officials, initial results from 20 of about 100 federal
inspections and 117 of about 670 state inspections that have been
completed or started show that operators are doing well in assessing
their pipelines and making repairs; but, in general, operators need to
better document their policies and procedures. Based on these initial
inspection results, PHMSA and states generally did not find many issues
that warranted enforcement actions to date.
In commenting on a draft of this report, the Department of
Transportation generally agreed with the report's findings and
recommendations and cited actions the department has already initiated
or plans to take to implement the recommendations.
Background:
Within the United States, there are about 295,000 miles of gas
transmission pipelines, which are part of larger gas pipeline systems
that transport natural gas from producing wells to users. (See fig. 1.)
Gas gathering lines collect natural gas from production facilities and
transport it to transmission pipelines. In turn, gas transmission
pipelines transport gas products to processing plants, and then on to
communities and large-volume users, such as power plants. Gas
distribution pipelines continue to transport natural gas from
transmission pipelines to residential, commercial, and industrial
customers.
Figure 1: Gas Pipeline System:
[See PDF for image]
Source: Pipeline and Hazardous Materials Safety Administration.
[End of figure]
PHMSA, within the Department of Transportation (DOT), administers the
national regulatory program to ensure the safe transportation of
natural gas and hazardous liquid by pipeline.[Footnote 3] PHMSA carries
out its mission through regulation, national consensus standards,
research, education, inspections, and enforcement when safety problems
are found. The agency 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. In general, PHMSA retains full
responsibility for inspecting and enforcing regulations on interstate
pipelines that cross state boundaries, but it has arrangements with 48
states, the District of Columbia, and Puerto Rico to assist with
overseeing intrastate pipelines. PHMSA allows state agencies the
flexibility to design their programs to best meet their needs, although
it conducts an annual audit of each state's inspection program. 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 performed its oversight role using uniform,
minimum safety standards that all pipeline operators must
meet.[Footnote 4] For gas transmission pipeline operators, these
standards are 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 thickness of the pipe required
and the pressure at which it can operate. Recognizing that pipeline
operators face different risks, depending on such factors as location
and the products they carry, PHMSA began exploring the concept of a
risk-based approach to pipeline safety in the mid-1990s.[Footnote 5]
The Accountable Pipeline Safety and Partnership Act of 1996 included
provisions for DOT to establish a demonstration program to test such a
risk-based approach.[Footnote 6] As a result, PHMSA established the
Risk Management Demonstration Program, which went beyond the agency's
traditional regulatory approach by allowing individual operators to
identify and focus on the risks unique to their pipelines. According to
a PHMSA official, the demonstration project identified the need for
operators to better understand the condition of their pipelines,
including the risks and threats to their pipelines. The agency
subsequently moved forward with a new regulatory approach--termed
integrity management--to supplement the existing uniform, minimum
regulations. Integrity management created a systematic process to
managing the safety of the pipeline and is designed to provide for
continual improvement. PHMSA established requirements for integrity
management for hazardous liquid pipeline operators with 500 or more
miles of pipelines in December 2000 and for operators with less than
500 miles in January 2002. In 2000, PHMSA was also exploring issues
related to integrity management for gas transmission pipelines,
including collaboration with the pipeline industry to develop consensus
standards for gas integrity management, which were subsequently
incorporated into the regulations. These consensus standards cover
issues such as establishing and conducting integrity management
programs and actions operators must take to assess the extent of
corrosion in their pipelines.
In 2003, PHMSA issued integrity management regulations for all
operators of gas transmission pipelines.[Footnote 7] As shown in figure
2, under these regulations, operators must identify and assess segments
of their pipelines that are located in "high consequence areas," which
are highly populated or frequently used areas, such as parks, where
pipeline leaks or ruptures could have the greatest impact on public
safety. Operators are required to collect and integrate data from their
entire pipeline system--such as maps, information on corrosion
protection, exposed pipeline, and threats from excavation or other
third-party damage--to identify the threats to their high consequence
areas. Pipeline threats include corrosion; welding defects and
failures; third-party damage (e.g., from excavation equipment); land
movement; and incorrect operation. Once operators have identified the
threats, they must perform a risk assessment to determine which
pipeline segments are most susceptible to those threats. Starting with
the pipelines that are most susceptible, operators must then assess the
condition of their pipelines--referred to as baseline assessments--on
half of their pipeline mileage in high consequence areas by December
2007 and the remainder by December 2012. Using the results of the
assessments, operators must repair or replace any defective sections of
pipeline. Operators are also required to perform preventive and
mitigative measures, such as installing computerized monitoring and
leak detection systems.[Footnote 8] In addition, operators are required
to reassess their pipelines in high consequence areas for corrosion
problems at least every 7 years and for all safety threats at least
every 10, 15, or 20 years, depending on the condition of the pipelines
and the stress under which the pipeline segments are operated.
Operators must also document processes to ensure actions for managing
pipeline integrity are applied consistently and that the results are
repeatable across the company. For example, operators are required to
have written processes for management of change, quality assurance, and
communication.
Figure 2: Integrity Management Process for Gas Transmission Pipelines:
[See PDF for image]
Source: GAO.
[End of figure]
Gas Integrity Management Benefits Public Safety, although Operators
Have Some Implementation Concerns, and Performance Measures Could Be
Improved:
The gas integrity management program is designed to improve pipeline
safety by supplementing existing standard safety requirements with risk-
based management principles, including performance measures to monitor
progress. For the first time, all operators are required to
systematically assess the condition of their pipelines in high
consequence areas and make identified repairs. As of December 31, 2005,
operators report having assessed about 33 percent of their pipelines in
high consequence areas and completed over 2,000 repairs. In addition,
we estimate that up to 68 percent of people living along natural gas
transmission pipelines are located in highly populated areas and are
expected to receive additional protection as operators continue to
assess and repair their pipelines in these areas. Furthermore, the gas
pipeline industry, state pipeline agencies, safety advocate
representatives, and operators with whom we spoke generally agree that
the program benefits public safety. While early indicators show that
integrity management benefits public safety, some operators noted that
the program is not without its costs. Operators also expressed
uncertainty about the program's documentation requirements. Despite
these concerns, operators are making good progress in implementing
integrity management, as demonstrated by the performance measures that
operators report semiannually to PHMSA. However, these performance
measures could be improved to better enable PHMSA to identify the
program's impact on public safety.
Integrity Management Offers Additional Protection Over Minimum Safety
Standards:
Prior to the integrity management program, there were, and still are,
minimum safety standards for the design, construction, operation, and
maintenance of all gas transmission pipelines that provide the public
with a basic level of protection from pipeline failures. For example,
all operators are required to have a system to protect their pipelines
from corrosion. Federal or state inspectors use a "checklist" approach
to determine whether operators have such a system and that it is
operating appropriately.[Footnote 9] However, the minimum safety
standards do not account for the differences in the kinds of threats
and degrees of risk that pipelines face. In addition, inspections of
the operators verify that the standards are being followed, but do not
evaluate the effectiveness of the protective measures put into place,
such as the corrosion protection system, because the standards do not
require operators to assess the integrity of their pipelines.
Consequently, some pipelines have operated for 40 or more years without
being assessed. However, 33 of 51 operators (about 65 percent) told us
they had assessed the integrity of some of their pipelines prior to the
integrity management regulations.
The gas integrity management program goes beyond existing minimum
safety standards by using risk-based management principles to provide
an additional level of safety to the public where the impact of
pipeline leaks, failures, or incidents could be the greatest. Risk-
based management has several key characteristics that help to ensure
safety--it (1) uses information to identify and assess risks; (2)
prioritizes risks so that resources may be allocated to address higher
risks first; (3) promotes the use of regulations, policies, and
procedures to provide consistency in decision making; and (4) monitors
performance. The gas integrity management program embodies each of
these characteristics. It requires operators to integrate information
from different sources (both internal and external) to identify the
risks specific to their pipelines and then use data from the assessment
of their pipelines to make necessary repairs and take preventive
measures. To prioritize risks for resource allocation, integrity
management focuses on high consequence areas and requires operators to
assess the riskiest segments of their pipelines first. Five operators
told us that the requirements of integrity management has helped focus
resources, and one said it has even helped to justify the need for
resources that would otherwise have been difficult to obtain. To
provide a level of consistency in how tasks are performed and decisions
are made, the integrity management program requires operators to
document their policies and procedures. In addition, PHMSA developed
inspection protocols and "frequently asked questions" to help define
the agency's expectations for operators and help ensure consistency in
inspections. According to PHMSA, having procedures, roles, and
responsibilities clearly defined is crucial for operators to ensure
continual and consistent management for safety. Finally, integrity
management requires operators to monitor their progress by reassessing
their pipelines at specified intervals. Operators must also report to
PHMSA semiannually on specific performance measures related to
integrity management. These measures include the total mileage of
pipelines and the mileage of pipelines assessed in high consequence
areas, as well as the number of repairs made and the number of
incidents, leaks, and failures identified in these areas.
We estimate that this risk-based approach should offer additional
safety benefits for up to 68 percent of the population living near gas
transmission pipelines; this estimate corresponds with PHMSA's estimate
of two-thirds of the population. Even though the integrity management
program applies to only pipelines in high consequence areas, which
account for about 7 percent of all transmission pipeline miles, the
population living along pipelines tends to be clustered in these areas.
Using Census data, we estimated that up to 68 percent of the people who
live near (within 660 feet) natural gas transmission pipelines are
located in highly populated areas and thus should be afforded
additional protection as a result of integrity management. (See fig.
3.)
Figure 3: Highly Populated Areas within 660 Feet of a Natural Gas
Transmission Pipeline:
[See PDF for image]
Sources: the U.S. Census Bureau and PHMSA (data); GAO (graphic).
[End of figure]
While operators do not report the location of their high consequence
areas, population is a key component to identifying these areas. Using
Census data to identify the population living along pipelines, we
estimated that about 22,000 miles of transmission pipelines could be
considered as being in highly populated areas, which is similar to the
20,294 miles of pipelines reported by operators as being in high
consequence areas. Therefore, our estimate of the highly populated
areas is a reasonable approximation of the high consequence areas.
Early Indicators Show That Integrity Management Is Beneficial, Despite
Some Operators' Concerns about Implementation:
Although the integrity management program is still being implemented, a
number of representatives from pipeline industry organizations, state
pipeline agencies, safety advocate groups, and operators 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. In
addition, operators must repair problems or anomalies identified in
their pipelines. As of December 31, 2005, 33 percent of the identified
pipelines in high consequence areas had been assessed, and over 2,000
repairs had been completed.
Six of the 51 operators we interviewed also pointed to the benefit of
improved communications within their companies. Investigations of
pipeline incidents have shown that, in some cases, an operator
possessed information that could have prevented an incident but did not
share the information with employees who needed it most. The integrity
management program requires operators to integrate pipeline data from
various sources within the company to identify threats to the
pipelines, leading to more interaction among different departments
within pipeline companies.
While all operators we contacted generally believe integrity management
is beneficial, the program is not without its costs. For example, over
half of the operators with whom we spoke said that they have hired
additional staff or contractors as a result of integrity management
requirements. Furthermore, one operator told us that, although it
assessed its pipeline before the gas integrity management program was
enacted, the operator now spends about 5,000 to 10,000 more hours per
year on assessments because it must integrate data from multiple
sources--some of which are formatted differently--requiring that the
operator make all data consistent before using it. Another operator
told us that implementation of the program was costly because its gas
transmission pipelines are located under pavement. These pipelines
could not be assessed using tools that run through pipelines, so the
operator had to excavate, visually assess, and repave over the
pipelines, which is costly. A third operator estimated that it had
spent between $8.5 million and $10 million on developing its integrity
management program and related systems. This operator also estimated
that its annual operating costs had increased by $16.5 million to $21.5
million to comply with the integrity management regulations, even
though it had an aggressive inspection and testing program prior to
those regulations.
Operators also cited other concerns about implementing their integrity
management programs. One of the more frequently identified concerns by
the operators, cited by 19 of the 51 operators we contacted (37
percent), was related to 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 integrity management requirements. In addition, operators must
document any integrity management related decisions to demonstrate that
they understand the risks to their pipelines and are systematically
managing their pipelines for these risks. For example, an operator must
document how it identified the threats to its pipeline and assessed the
risks, how these risks will be managed, who was involved in these
decisions and their qualifications, and the data they used. 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 program has been inspected.
Initial inspections of operators by PHMSA and state pipeline agencies
have confirmed that some operators are experiencing difficulty with
documentation but generally are 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 a majority of the operators is the
requirement to reassess their pipelines for corrosion problems at least
every 7 years. We recently reported that while reassessments are
useful, the 7-year requirement appears to be conservative.[Footnote 10]
Performance Measures Should Show Impact of Integrity Management Over
Time, but Could Be Improved:
Operators report to PHMSA semiannually on several performance measures
that show the progress operators have made in implementing integrity
management and, over time, should demonstrate the impact of integrity
management on safety. Table 1 lists the performance measures and shows
the progress operators reported as of December 31, 2005.
Table 1: Integrity Management Performance Measures Reported by
Operators as of December 31, 2005:
Pipeline performance measures for gas transmission pipelines: Total
miles of pipelines reported;
Statistics: 296,138.
Pipeline performance measures for gas transmission pipelines: Total
miles of pipelines assessed;
Statistics: 50,441.
Gas transmission pipelines within high consequence areas: Total miles
reported;
Statistics: 20,294.
Gas transmission pipelines within high consequence areas: Total miles
assessed;
Statistics: 6,707.
Gas transmission pipelines within high consequence areas: Leaks[A];
Statistics: 221.
Gas transmission pipelines within high consequence areas: Failures[B];
Statistics: 28.
Gas transmission pipelines within high consequence areas: Incidents[C];
Statistics: 19.
Gas transmission pipelines within high consequence areas: Immediate
repairs completed[D];
Statistics: 340.
Gas transmission pipelines within high consequence areas: Scheduled
repairs completed[E];
Statistics: 1,981.
Source: PHMSA.
[A] A leak is an unintentional escape of gas from a pipeline that does
not result in an injury, death, or $50,000 in property damage.
[B] Failure is a general term used to imply that a part in service has
become completely inoperable; is still operable but is incapable of
satisfactorily performing its intended function; or has deteriorated
seriously, to the point that it has become unreliable or unsafe for
continued use.
[C] An incident is defined as an event that involves a release of gas
from a pipeline and (1) a death or personal injury necessitating in-
patient hospitalization or (2) estimated property damage, including
cost of gas lost, of $50,000 or more, or an event that is significant,
in the judgment of the operator.
[D] An immediate repair must be made when specific conditions are
identified related to the strength of a pipeline, a dent with an
indication of metal loss or cracking, or an anomaly judged to require
immediate action.
[E] 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.
[End of table]
Total mileage reported and assessed: As a result of technology that
many operators are using to assess their pipelines, operators are
assessing a much greater portion of total pipeline mileage than that
which is located in high consequence areas. In addition, they are
making repairs to these pipelines. Of the 51 operators we contacted, 36
(71 percent) are using in-line assessment tools that run inside the
pipelines to assess the integrity of some or all pipelines within high
consequence areas. These tools must be inserted and removed from the
pipelines at designated locations that often run through areas other
than high consequence areas. Consequently, operators reported having
assessed about 44,000 miles of pipelines located outside high
consequence areas, which represents about 15 percent of all gas
transmission pipelines. Operators that use the in-line assessment tools
told us that they assess the entire distance of pipeline between the
insertion and retrieval points because, in doing so, they gather
additional insights into the condition of their pipeline. While
operators are not required to report to PHMSA the results of the
assessments in areas outside of the high consequence areas, a number of
operators with whom we spoke said that they plan to make or have made
repairs identified through the assessments, regardless of where they
are identified, thereby expanding the benefits of integrity management
beyond the high consequence areas.
High consequence mileage reported and assessed: As of December 2005,
operators had assessed about 6,700 miles of their 20,000 miles of
pipeline --or about 33 percent--located in high consequence areas. This
progress indicates that operators 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. Operators must then complete
the rest of their baseline assessments by December 2012. Most of the
operators with whom we spoke (48 of 51) said they had no major concerns
about their ability to complete baseline assessments, as required.
Incidents, leaks, and failures: While pipelines are considered a
relatively safe mode of transporting gas, integrity management is
designed to improve pipeline safety and should lead to a reduction in
the number of incidents, leaks, and failures over time. PHMSA and the
pipeline industry have generally used the number of incidents, related
fatalities, and injuries as a measure for determining the safety of
pipelines. Since the inception of integrity management, 19 of the 305
incidents reported for all pipelines in fiscal years 2004 and 2005
occurred in high consequence areas. The majority of the incidents
reported in high consequence areas--10 of the 19 incidents--were caused
by third-party damage. Leaks have traditionally been reported by
operators in their annual reports, but this information is not
generally aggregated nationwide, so it is not possible to determine how
leaks in high consequence areas compare with those in other areas.
Failures were not typically reported to PHMSA prior to integrity
management; therefore, it is not possible to compare the number of
failures in high consequence areas with those in other areas. As PHMSA
collects information on incidents, leaks, and failures over time, the
agency will be able to identify trends and make these comparisons.
Immediate and scheduled repairs completed: In addition to assessing
pipelines, operators are also making progress in fulfilling the
requirement to repair problems found on pipelines in high consequence
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 high
consequence areas. While it is not possible to determine the number of
needed repairs that 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 down the
pipeline for immediate repair.
While the integrity management performance measures should allow PHMSA
to measure the impact of the program, the measures related to
incidents, leaks, and failures could be improved to better allow for
optimal comparison of performance over time and make them more
consistent with other pipeline safety measures. For example, incident
reporting requirements do not include an adjustment for changes in the
price of natural gas, even though the value of gas released is a key
factor in determining whether an incident must be reported to PHMSA. A
reportable incident is defined, in part, as when the estimated property
damage, including the cost of gas lost, meets a threshold of $50,000.
Since this reporting threshold has not been adjusted over time, as the
price of gas has increased, it is difficult to use the number of
incidents over time as an indicator of pipeline safety. For many years
the price of gas was relatively stable. However, since 1999, natural
gas prices have increased by about 179 percent, while the threshold for
reporting an incident has not changed. As a result, smaller releases of
gas from a pipeline meet the definition of an incident and artificially
inflate the number of pipeline incidents. For example, in 1999, a
release of about 16,100 thousand cubic feet of gas would have triggered
the incident reporting requirement, compared with only about 5,800
thousand cubic feet of gas in 2005. In 2002, PHMSA began collecting
information on the value of gas released during an incident. Adjusting
the 183 gas transmission pipeline incidents that occurred in 2005 to
reflect the price of gas in 1999 would have resulted in about 27 fewer
incidents. PHMSA officials recognize the advantages of changing the
reporting requirements to adjust for the changing price of gas or to be
based on the volume of gas rather than its value, but PHMSA has not yet
initiated a rule to change the reporting requirement.
In addition, the usefulness of the performance measure data is limited
in part by inconsistencies in the reporting of causes of incidents and
leaks in high consequence areas compared with the rest of the pipeline
system. For example, to report a leak within a high consequence area,
operators may choose from three separate corrosion causes: internal
corrosion, external corrosion, or stress-corrosion cracking.[Footnote
11] In contrast, to report a leak outside of a high consequence area,
operators use one overall category for corrosion. Without consistent
reporting of causes, it is difficult to compare the reasons for
incidents and leaks in high consequence areas with those along the rest
of the pipeline system. We are making recommendations to improve the
consistency of the integrity management performance measures.
PHMSA and State Pipeline Agencies Plan to Use Inspection Tools
Developed by PHMSA to Complete the Initial Round of Inspections by
2009:
PHMSA has developed various tools to help prepare and assist federal
and state inspectors in conducting inspections. These inspection tools
include guidance documents for evaluating operators' integrity
management programs, training courses to provide inspectors with the
knowledge of technical issues, and communication mechanisms. Overall,
most state pipeline agency officials told us that these tools are
useful; although about half of the state officials with whom we spoke
have found it difficult to schedule the required training courses, and
the majority have some concerns about the adequacy of their staffing.
To address these concerns, PHMSA has taken steps to make it easier for
state inspectors to attend training and supports a proposal from states
to provide additional funding that could be used for staffing needs.
PHMSA and states have begun inspections and expect to complete the
first round of inspections no later than 2009. PHMSA has completed 20
of about 100 inspections, and states have begun or completed 117 of
about 670 inspections, as of June 2006 and January 2006, respectively.
PHMSA and state officials reported that the initial results from these
inspections show that operators are doing well in implementing the
assessment and repair requirements of the integrity management program,
but they need to improve documentation of their program's processes.
PHMSA Has Developed Tools to Prepare Inspectors for Integrity
Management Inspections:
In collaboration with state pipeline agencies, PHMSA developed guidance
documents--inspection protocols, supplemental guidance, and "frequently
asked questions"--to assist federal and state inspectors in evaluating
operators' integrity management programs. The inspection protocols
provide a roadmap for conducting inspections. The protocols walk the
inspectors through the integrity management requirements in the
regulations to help inspectors verify that an operator's program
complies with the regulations. These inspection protocols are available
to the public, and many operators with whom we spoke said they had
reviewed the protocols when developing their programs. To supplement
the inspection protocols, PHMSA has provided inspectors with additional
guidance on the types of questions to ask operators, documents to
review, and key elements to consider in evaluating operators' programs.
However, this supplemental guidance has not been provided to operators:
it is intended to be suggestions for inspectors rather than
requirements for operators because PHSMA expects programs to differ,
given that each operator is unique. In addition, PHMSA posts
"frequently asked questions" and corresponding answers to its Web site.
This tool further clarifies the regulations and PHMSA's expectations
for what should be included in operators' plans.
PHMSA also developed a series of required training courses to inform
federal and state inspectors of technical topics relevant to the
integrity management regulations. The 10 training courses--4 classroom
and 6 computer-based courses--take about 20 days to complete and
address the integrity management inspection protocols as well as
specific threats to the pipelines (such as stress-corrosion cracking,
and internal and external corrosion) and different assessment
techniques (such as in-line assessment and direct assessment).[Footnote
12] While most (13 of 21) state officials with whom we spoke consider
the required training to be important, about half noted that it is
difficult for inspectors to schedule the classroom training on
inspection protocols. PHMSA has taken steps to help state inspectors
attend this training, such as offering the course in each of the five
PHMSA regional offices in 2005 and providing travel funds for two
inspectors from each state to attend. In addition, PHMSA maintains
flexibility in scheduling the course and schedules classes once it
receives enough requests. As a result, according to PHMSA records, at
least one inspector from 46 of 47 states has attended the required
training. The remaining state agency reported that it had confirmed
that the gas transmission pipeline operators in its state do not have
any pipelines in high consequence areas.
Another tool that PHMSA and state pipeline agencies may use is on-the-
job training. PHMSA invites state inspectors to participate in PHMSA-
led inspections of interstate operators that allow state inspectors to
learn how PHMSA conducts inspections, to ask questions, and to gain
experience in using the protocols. The majority (12 of 21) of state
officials with whom we spoke indicated that their inspectors have, or
will have, participated in PHMSA-led inspections before conducting
their own inspections. As time permits, PHMSA inspectors also will
attend state-led inspections to provide guidance and answer questions.
Finally, PHMSA has implemented several mechanisms--such as Web sites,
conference calls, and meetings--to communicate with federal and state
inspectors. For example, PHMSA created a restricted Web site where
federal and state inspectors may obtain guidance documents, access
information pertaining to inspections, pose questions on the integrity
management program, and communicate with other inspectors. Through this
tool, inspectors may learn from other inspectors' experiences by
reviewing documentation of completed inspections that are posted. All
completed federal inspections will be posted, and 28 states reported
that they intend to post the results of their inspections as well.
PHMSA also holds conference calls and periodic meetings with federal
and state inspectors to discuss their experiences and identify
opportunities to improve the inspection program. In addition, PHMSA
keeps state pipeline agencies informed about gas integrity management
through regular updates through the National Association of Pipeline
Safety Representatives. These updates include Web site links and status
reports on issues such as training classes, upcoming inspections, and
work groups. Although communication between PHMSA and states has been
problematic in the past, the majority of states (41 of 47) reported
that PHMSA's efforts to improve communication and guidance pertaining
to gas integrity management have been useful.[Footnote 13]
First Round of Inspections Is Expected to Be Completed by 2009 and
Initial Inspections Show Operators Are Making Good Progress in
Conducting Assessments:
PHMSA and state pipeline agencies plan to conduct more than 700 gas
integrity management inspections, with the majority expected to be
completed no later than 2009.[Footnote 14] PHMSA anticipates conducting
a total of about 100 inspections of interstate gas transmission
pipeline operators, of which about 80 are expected to have pipelines in
high consequence areas. The 47 state pipeline agencies anticipate
conducting a total of about 670 inspections of intrastate gas
transmission operators, including those with and without pipelines in
high consequence areas.[Footnote 15] The majority of states (41 of 47)
reported that they will each conduct fewer than 20 inspections,
although one state reported that it will conduct as many as 256
inspections. Just as operators continually assess their pipelines,
PHMSA and states plan to inspect operators' programs on a regular
basis. PHMSA plans to conduct inspections of operators' programs at
least once every 3 or 4 years, and more than half of the state agencies
plan to conduct these inspections at least once every year or 2.
To conduct these inspections, PHMSA currently has 22 trained
inspectors, 9 of which are assigned exclusively to conducting integrity
management inspections. In 2002, we reported that PHMSA's efforts to
identify the resources and expertise needed to implement its integrity
management approach were hampered by the lack of an up-to-date
assessment of current and future staffing and training needs.[Footnote
16] In response to our recommendation to develop a workforce plan,
PHMSA drafted a workforce plan in March 2005 that considers the
essential elements of such a plan. For example, the plan identifies
trends likely to impact the number and types of field staff needed and
identifies competencies needed to meet PHMSA's strategic goals. In
addition, the plan includes an examination of how its workforce should
be deployed across the organization and suggests assigning staff to
regions based on regional workload and need.
State officials with whom we spoke reported additional staffing
concerns as a result of integrity management inspections. State
pipeline agencies generally employ between one and five inspectors to
perform these inspections, although they may not be dedicated to
integrity management. The Pipeline Safety and Improvement Act of 2002
increased the workload of state pipeline agencies by establishing three
new inspection requirements for integrity management, operator
qualifications and public awareness programs.[Footnote 17] However,
state staffing and funding levels were generally not increased to
fulfill these additional responsibilities. States are handling the
increased workload in various ways, such as combining inspections,
modifying the frequency of inspections, or focusing efforts on
completing one new inspection at a time. For example, a few states
focused on completing operator qualifications inspections before
starting integrity management inspections. In addition, 11 state
officials said that it is difficult to hire qualified staff, such as
engineers, who are needed for the technical nature of the integrity
management inspections. According to two state officials, state
agencies are losing trained inspectors because the state salaries are
typically lower than those paid by operators. To help states deal with
increased workload and hiring issues, the National Association of
Pipeline Safety Representatives has recommended that PHMSA be allowed
to reimburse state pipeline agencies up to 80 percent of their
inspection program costs--up from the current allowance of up to 50
percent of program costs. PHMSA supports this increase, and such an
increase is included as part of the proposed Pipeline Safety
Improvement Act of 2006 (H.R. 5678 and H.R. 5782).[Footnote 18]
PHMSA and about half of the state pipeline agencies have begun
conducting inspections of operators' implementation of the integrity
management requirements. PHMSA and states generally started initial
integrity management inspections in 2005.[Footnote 19] As of June 2006,
PHMSA reported having completed 20 of about 100 inspections,
encompassing about 7,063 of the 10,039 miles in high consequence areas
that PHMSA is responsible for inspecting. About half of the state
pipeline agencies reported that they had started or completed 117 of
about 670 inspections as of January 31, 2006. In response to our
survey, most of the remaining states reported that they anticipate
beginning inspections in 2006. PHMSA selected the operators for initial
inspections based on their history of working well with PHMSA and their
expected level of program development to allow PHMSA inspectors to gain
experience with its inspection protocols and process. After the first
nine inspections, PHMSA met with inspectors to discuss the process and
has made some revisions to the protocols based on inspectors'
recommendations. PHMSA's current and future inspection schedule is
determined by using a risk-ranking system that considers factors such
as an operator's compliance history and pipeline mileage. Using this
system should result in inspections of operators with a higher
potential of having an incident or problem prior to those operators
with a lower potential. According to PHMSA's "Guidelines for States
Participating in the Pipeline Safety Program," states should use the
date of the last inspection and operating history to prioritize
operators for inspections. Seven state officials told us they initially
inspected all operators' programs to ensure they had a program and had
identified their high consequence areas, and that a more detailed
inspection would be done in the future.
According to a PHMSA official and state officials, initial integrity
management inspections show that operators are generally experiencing
few problems with assessing and repairing pipelines, although some
operators are having trouble documenting their processes and procedures
and thus are failing to get adequate credit for their efforts. PHMSA
considers documentation important for ensuring that an operator is
appropriately implementing the program, that the operator is committed
to continued implementation, and that the program is being consistently
implemented throughout an operator's organization. It is also important
to document the processes and procedures so that knowledge of the
process is not lost as staff changes occur. According to PHMSA, the
documentation should include identifying the person involved in the
decision or task, information needed and steps taken to make the
decision or complete a task, and the results. Two state officials said
that the operators in their states with few transmission pipeline miles
were making efforts to comply but that they were struggling with
implementing integrity management requirements. For example, the
operator of a paper mill that also owns and operates about 8 miles of
gas transmission pipeline to transport gas to its production facility
stated that it is struggling to understand and comply with integrity
management requirements. According to PHMSA and state officials, as
operators continue developing and implementing their integrity
management programs, and as they are provided feedback during
inspections, the issues identified during these initial inspections
should be resolved.
PHMSA is continuing to determine the appropriate enforcement actions,
if any, as a result of its initial inspections and will consider all
available enforcement tools, including civil penalties. As of June 30,
2006, six enforcement actions have been processed but no fines have
been assessed. Four operators have been issued a Notice of Amendment,
which indicates a need to improve their written processes and
procedures. In addition, two of these operators have also received a
Notice of Probable Violation and Proposed Compliance Order for
potentially failing to fully comply with the risk analysis requirement
in the rule. According to a PHMSA official, the enforcement actions
processed to date are proposed actions and will become final after the
operators have had an opportunity for a hearing. PHMSA has developed a
process that provides consistent standards for the inspectors and
regional directors to use in determining when an enforcement action is
warranted. The process lays out criteria to determine the severity of
each issue identified during the inspection, whether enforcement action
is appropriate and, if so, what type of action to take. As part of
their agreements with PHMSA, most states are responsible for taking
appropriate enforcement actions as a result of their inspections. Most
state officials said that issues identified during their initial
integrity management inspections have not warranted enforcement
actions. However, one state official with whom we spoke issued a notice
of violation to an operator that had not developed an integrity
management plan. The operator, with about 11 miles of gas transmission
pipelines, told the state that it was unaware of the requirement to
develop an integrity management program. The state official told us
that, after the inspection, the operator immediately began developing a
program, and the state inspector is to revisit this operator within 6
months.
Conclusions:
The gas integrity management program has made a promising start. The
program's risk-based approach is supported by industry, state pipeline
agencies, safety advocates, and operators. Although the national
transmission pipeline system is extensive, much of the population that
is potentially affected by a pipeline event is concentrated in highly
populated areas, which will be provided additional protection through
the program. Thus far, operators are successfully implementing the
critical assessment and repair requirements, and their documentation
concerns should be resolved as operators gain experience with the
program and receive feedback during inspections. While the progress in
implementing the program to date is encouraging, PHMSA and state
oversight will be critical to ensure that operators continue to
effectively implement integrity management. As the program matures,
PHMSA's performance measures should allow the agency to quantitatively
demonstrate the program's impact on the safety of pipelines. However,
relatively minor changes in how some of the measures are reported could
help improve their usefulness and PHMSA's ability to analyze and
demonstrate the program's impact over time.
Recommendations for Executive Action:
To improve the consistency and usefulness of the integrity management
performance measures, we are recommending that the Secretary of
Transportation direct the Administrator for the Pipeline and Hazardous
Materials Safety Administration to take the following two actions:
* revise the definition of a reportable incident to consider changes in
the price of natural gas and:
* establish consistent categories of causes for incidents and leaks on
all gas pipeline reports.
Agency Comments and Our Evaluation:
We provided a draft of this report to DOT for review and comment. We
received oral comments from DOT officials, including the Assistant
Administrator and Chief Safety Officer of PHMSA. The officials
generally agreed with the report's findings and recommendations. They
agreed with the need to revise the definition of a reportable gas
transmission pipeline incident, noting that doing so provides a more
realistic and consistent basis for reporting. PHMSA has already begun
informal discussions with various parties on this issue and expects to
initiate the rule making necessary to change the definition of a
reportable gas incident soon. The officials also agreed with the
recommendation to have consistent categories of causes for incidents
and leaks for all gas pipeline reports. PHMSA is evaluating several
alternatives to reconcile the differences in the categories and expects
to initiate action to implement this recommendation.
We are sending copies of this report to congressional committees and
subcommittees with responsibility for transportation safety issues; the
Secretary of Transportation; the Administrator, PHMSA; the Assistant
Administrator and Chief Safety Officer, PHMSA; and the Director, Office
of Management and Budget. We will also make copies available to others
upon request. This report will be available at no charge on the GAO Web
site at [Hyperlink, http://www.gao.gov].
If you have any questions about this report, please contact me at
siggerudk@gao.gov or (202) 512-2834. Contact points for our offices of
Congressional Relations and Public Affairs may be found on the last
page of this report. Staff who made key contributions to this report
are listed in appendix III.
Signed by:
Katherine A. Siggerud:
Director, Physical Infrastructure Issues:
Congressional Committees:
The Honorable Ted Stevens:
Chairman:
The Honorable Daniel K. Inouye:
Co- Chairman:
Committee on Commerce, Science and Transportation:
United States Senate:
The Honorable Don Young:
Chairman:
The Honorable James L. Oberstar:
Ranking Democratic Member:
Committee on Transportation and Infrastructure:
House of Representatives:
The Honorable Joe Barton:
Chairman:
The Honorable John D. Dingell:
Ranking Minority Member:
Committee on Energy and Commerce:
House of Representatives:
[End of section]
Appendix I: Scope and Methodology:
The Pipeline Safety Improvement Act of 2002 directed GAO to assess the
effects on public safety stemming from the gas transmission pipeline
integrity management program. Accordingly, the objectives of our report
were to examine (1) the effect on public safety of the gas transmission
pipeline integrity management program and (2) the plans of the Pipeline
and Hazardous Materials Safety Administration (PHMSA) and state
pipeline safety agencies to oversee gas transmission pipeline
operators' implementation of integrity management requirements. To
address these objectives, we reviewed laws, regulations, performance
measure data, and PHMSA guidance and inspection reports related to the
gas integrity management program. We also interviewed PHMSA officials
and representatives from gas pipeline trade associations, pipeline
safety advocacy groups, state pipeline agencies, and gas transmission
pipeline operators. In addition, we reviewed prior GAO reports related
to pipeline safety.
To determine the effect that the gas integrity management program
requirements have had on public safety, we analyzed how those
requirements compare with minimum safety requirements to understand
what additional requirements operators were subject to as a result of
integrity management. We discussed with PHMSA officials how the
regulations were designed and developed to improve public safety. Since
the integrity management requirements apply to a relatively small
percentage of all transmission pipeline miles--about 7 percent--we
estimated the percentage of the population living along pipelines that
should receive additional protection as a result of integrity
management because they are located in highly populated areas. We used
Census data to estimate the percentage of the population that lives
within 660 feet of a transmission pipeline that are located in urban
areas, which would be considered highly populated areas. We used Census
data to identify highly populated areas because the specific locations
that operators have identified as high consequence areas were not
readily available. Operators have identified a total of 20,294 miles of
gas transmission pipelines in high consequence areas, and we have
likewise identified a total of about 22,000 miles of pipelines in
highly populated areas. Therefore, our estimate of pipelines in highly
populated areas is a reasonable approximation of the pipelines in high
consequence areas.
To identify and understand the benefits and challenges the operators
face in developing and implementing their integrity management
programs, we contacted 51 gas transmission pipeline operators to
discuss their experiences and views on the program. We selected a range
of operators with either large or small numbers of transmission
pipeline miles since this could indicate the level of resources a
particular operator would have to draw from to develop its integrity
management program. We also selected operators based on a mixture of
interstate and intrastate operators and considered the proportion of
pipeline miles that each operator had in high consequence areas in our
selection process. The information that we obtained from these
operators is not generalizable to all gas transmission pipeline
operators. We also discussed the integrity management program and its
requirements with gas pipeline trade associations, pipeline safety
advocacy groups, and state pipeline agencies to obtain their opinions
on the benefits, challenges, and performance measures of the program.
In addition, we analyzed the integrity management performance measure
data reported by operators to PHMSA. We assessed the internal controls
and the reliability of the data elements needed for this engagement and
determined that they were sufficiently reliable for our purposes. We
compared the reporting requirements for integrity management
performance measures with other pipeline reported data. Given the early
stages of implementation of the integrity management program, we
determined that there was not enough comparable historical data to
conduct a trend analysis to quantify the impact of the program to date.
To determine PHMSA's plans to oversee operators' implementation of the
integrity management program, we spoke with PHMSA officials about the
inspection tools it developed to understand the purpose of the tools,
their development, information that both federal and state inspectors
receive about them, and plans for continual evaluation and improvement
of the inspection program. We also reviewed the integrity management
regulations, inspection protocols, supplemental guidance, frequently
asked questions, and other guidance documents that inspectors may use
to conduct integrity management inspections. While we compared the
inspection protocols with the gas integrity management regulations to
ensure that the protocols are aligned with the regulations, we did not
evaluate the adequacy of these documents. We reviewed PHMSA
requirements for both integrity management and core training, the
schedule of training classes, and attendance records of state
inspectors who have attended training on the inspection protocols. We
also reviewed PHMSA's schedule of inspections and documentation on how
the agency prioritizes operators for inspections. In addition, we
reviewed PHMSA's workforce plan dated March 2005 to understand the
agency's efforts to identify the resources and expertise needed for
integrity management.
To understand the plans of state pipeline agencies to oversee
operators' implementation of integrity management requirements, we
surveyed the 46 state pipeline agencies and the District of Columbia
pipeline agency that have responsibility for conducting gas integrity
management inspections.[Footnote 20] We pretested the survey with three
states prior to deployment. The survey covered state plans for
inspections, resources and challenges, and communication with PHMSA.
All 46 state agencies and the District of Columbia responded to our
survey. (See app. II for a copy of the survey and aggregated results.)
We then selected 15 states to contact to gain additional information on
challenges the states face as a result of integrity management,
benefits of the program to the pipeline industry, results of
inspections started or completed, performance measures, and
communication with PHMSA. We considered the following factors when
selecting states to contact: geographic dispersion, whether inspections
had been started or completed as of January 31, 2006, and whether
states reported facing staffing and/or training challenges to a great
or very great extent. In addition, we contacted three states prior to
developing the survey. In total, we spoke with officials from 21 state
pipeline agencies. These state agencies started or completed 103 of the
117 inspections started or completed, as of January 31, 2006. However,
the information obtained from these conversations is not generalizable
to all state pipeline agencies. We also reviewed documents from the
National Association of Pipeline Safety Representatives to better
understand the role of state pipeline agencies in overseeing operators.
We also reviewed PHMSA's guidance for state pipeline programs but did
not evaluate PHMSA's oversight of state pipeline programs.
To understand the extent to which operators were complying with the
integrity management requirements, we reviewed reports from 10 PHMSA
inspections and 10 inspections from two states. Our review of the
inspection reports was for illustrative purposes, and the results of
our review cannot be generalized to all operators. We also spoke with
PHMSA officials about their enforcement program and enforcement actions
to date, and we reviewed regulations and PHMSA guidance on what
enforcement actions may be taken and how PHMSA determines the
appropriate action to take as a result of gas integrity management
inspections. Since states were not required to develop a separate
enforcement plan for gas integrity management and most state officials
with whom we spoke had not taken any enforcement actions, we did not
review state enforcement programs.
[End of section]
Appendix II: Results of State Pipeline Agency Survey:
United States Government Accountability Office:
Survey of State Pipeline Agencies:
Gas Integrity Management Program Inspections:
Introduction:
The U.S. Government Accountability Office (GAO), an independent
congressional agency, was required by the Pipeline Safety Improvement
Act of 2002 (PL 107-355), to assess and evaluate the effects on public
safety of the requirements for the implementation of gas transmission
pipeline integrity management programs (IMP). As part of our work, GAO
is reviewing how the Office of Pipeline Safety (OPS) within the
Pipeline and Hazardous Materials Safety Administration plans to ensure
that pipeline operators are complying with the IMP regulations. Given
state pipeline agencies' role in inspecting intrastate pipeline
operators, we would like to understand the extent to which states will
be inspecting operators' implementation of IMP. The following survey is
intended to help us understand state plans for conducting IMP
inspections, including the development of an inspection program and
resources required to conduct inspections. GAO is not auditing state
inspection programs in any way.
Instructions for Completing This Questionnaire:
This questionnaire can be filled out using MS-Word and returned via
Email, or if you prefer, you may print the questionnaire and complete
it by hand. If you complete it by hand, you can return your survey via
fax or mail.
If you are completing the survey in MS-Word, follow these instructions:
* Please use your mouse to navigate by clicking on the field or check
box you wish to answer.
* To select a check box or button, simply click on the center of the
box.
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box and the `X' will disappear.
* To answer a question that requires that you write a comment, click on
the answer box ___ and begin typing.
These boxes are highlighted in yellow. The box will expand to
accommodate your answer.
To assist us, we ask that you complete and return this survey by
Friday, March 3, 2006.
To return by Email: Once the survey is completed, save this file to
your computer desktop or hard drive and attach the file as part of your
Email message to FrevertH@gao.gov or EdelsteinM@gao.gov:
To return by fax: Print the survey, complete it by hand, and fax it to:
202-512-4852. Please fax to the attention of Heather Frevert or Maria
Edelstein.
To return by mail: Print the survey, complete it by hand, and mail it
to:
Heather Frevert or Maria Edelstein:
GAO:
441 G Street, NW, Room 2T23B:
Washington, DC 20548:
If you have any questions about the contents of this questionnaire,
please contact:
Heather Frevert:
Phone: (202) 512-4203:
e-mail: FrevertH@gao.gov
Or:
Maria Edelstein:
Phone: (202) 512-6449:
e-mail: EdelsteihnM@gao.gov:
Respondent Information:
Please provide the following information for the individual
coordinating the completion of this survey so that we may contact them
to clarify any responses, or obtain additional information, if
necessary.
Name:
Title: Agency: Telephone Number: ( ) - , Ext:
E-mail Address: @:
Before completing the survey, please note the following:
* Unless otherwise indicated, all responses should be made about your
program at the state level.
* There is space for your comments at the end of the survey.
* We recognize that it is early in the IMP implementation process, and
that your program may change, as well as your opinions about the
process. We ask that you answer these survey questions as they pertain
to your current program status and your opinions as of today.
Integrity Management Program Regulations:
1. How many gas transmission pipeline operators do you currently have
oversight responsibility for?
Operators;
No of Operators: 1-20;
Frequency: 39.
Operators;
No. of operators: 21-50;
Frequency: 6.
Operators;
No. of Operators: over 50;
Frequency: 2.
2. How many gas integrity management program (IMP) plans do you expect
to have oversight responsibility for, given that multiple operators may
follow the same IMP plan?
Plans;
No. of IMP's: 1-20;
Frequency: 41.
Plans;
No. of IMP's 21-50;
Frequency: 3.
Plans;
No. of IMP's: over 50;
Frequency: 2.
Results of State Pipeline Agency Survey:
3. Does your state have its own gas IMP regulations that are separate
from the federal IMP regulations?
No (46):
Yes (1) --> 3a. If yes, briefly explain how your regulations are
different than federal IMP regulations.
4. To what extent do you expect that gas IMP requirements will protect
public safety?
Very great extent. (3)
Great extent . (10)
Moderate extent. (16)
Some extent. (8)
Little or no extent . (0):
Don't know. (9) (Note: No response = 1):
5. In measuring the effectiveness of the gas transmission integrity
management regulations, do you currently collect any performance
measures that are above and beyond what the federal gas IMP rules
require?
No (45):
Yes (2):
6. In your opinion, are additional federal performance measures needed
to measure the effectiveness of the gas transmission integrity
management regulations?
No (17):
Yes (4):
Undecided (25) (Note: No response =1):
Gas Integrity Management Program Inspections:
7. Will you follow the Office of Pipeline Safety's (OPS) inspection
protocols when conducting gas IMP inspections?
Yes, with no changes to the protocol . (43) SKIP TO QUESTION #9:
Yes, but with some changes to the protocol. (3) SKIP TO QUESTION #9:
No, we will not follow the OPS protocols. (0) (Note: No response= 1):
8. If you will not follow the OPS protocols when conducting
inspections, will you use inspection protocols that your state
developed?
No n.a. (0 responses to "No, we will not follow . . .", above):
Yes n.a. (0 responses to "No, we will not follow . . .", above):
9. Has your state started inspections of gas IMP plans?
(23) No SKIP TO QUESTION #10
(23) Yes:
a. On approximately what date did you start the inspections?
l (MM/ /YY) (Responses ranged from 3/05 to 2/06, with one respondent
starting inspections in 5/01):
b. As of January 31, 2006, how many gas IMP inspections have been
completed?
Inspections (7 Respondents reported 0 completed inspections, 9 reported
between 1 and 3, 3 reported between 4 and 7, and 1 reported 50, and 3
indicated no response):
c. As of January 31, 2006, how many gas IMP inspections have been
started but not completed?
Inspections SKIP TO QUESTION #11 (8 respondents reported 0, 9
respondents reported between 1 and 4, 1 reported 9, 1 reported 12, 4
gave no response).
10. If you have not begun inspections, have you set a date for gas IMP
inspections to begin?
(5) No:
(17) Yes On approximately what date will inspections begin?
(Responses ranged from April 2006 through the end of 2006, with 1
respondent saying 2007) (Note: No response = 1):
11. How long do you anticipate it will take your state to inspect all
of the gas IMP plans you are responsible for?
Up to one year. 23
Between one and two years. 15
Between two and three years. 4
More than three years. 3
Other time frame (please specify ) . 0:
(Note: No response = 2):
12. How often do you anticipate that you will inspect each of the gas
IMP plans you are responsible for?
Once a year. 10:
Once every two years. 16:
Once every three years. 14:
Other time frame(s) (please specify ). 6.
(Note: No response = 1)
13. Do you plan to report the results of completed gas IMP inspections
to OPS?
No 7 --> If no, please explain: (Note: 5 explained there is no
requirement to report)
Yes 28:
Undecided 10 (Note: No response = 2):
State Resources:
14. How would you describe the number of staff that your agency
currently has to implement the gas IMP inspection program?
We do not have enough staff at this time . 27
We have enough staff at this time . 18
We have more than enough staff at this time. 1 (Note: No response = 1):
15. How many inspectors do you currently have that can perform gas IMP
inspections?
Inspectors: 0;
Frequency: 3.
Inspectors: 1;
Frequency: 14.
Inspectors: 2;
Frequency: 15.
Inspectors: 3;
Frequency: 5.
Inspectors: 4;
Frequency: 7.
Inspectors: 5;
Frequency: 3.
16. To date, how many inspectors received OPS training on inspection
protocols, and are currently available to conduct inspections?_
Inspectors Frequency:
Inspectors: 0;
Frequency: 4.
Inspectors: 1;
Frequency: 13.
Inspectors: 2;
Frequency: 17.
Inspectors: 3;
Frequency: 5.
Inspectors: 4;
Frequency: 4.
Inspectors: 5;
Frequency: 4.
17. To what extent has the state's frequency of conducting other
pipeline inspections been impacted by the addition of gas IMP
inspections?
Very great extent: 2
Great extent: 7
Moderate extent: 17
Some extent: 9
Little or no extent: 7:
Don't know: 5:
18. To what extent does your agency experience the following challenges
as a result of implementing the gas IMP inspection program?
a. Staffing challenges?;
A very great extent: 7;
Great extent: 11;
Moderate extent: 15;
Some extent: 6;
Little or no extent: 6;
Not sure: 2;
No answer: [Empty].
b. Funding challenges?;
A very great extent: 5;
Great extent: 7;
Moderate extent: 7;
Some extent: 10;
Little or no extent: 13;
Not sure: 4;
No answer: 1.
c. Training challenges?;
A very great extent: 8;
Great extent: 16;
Moderate extent: 12;
Some extent: 7;
Little or no extent: 3;
Not sure: 0;
No answer: 1.
d. Another challenge?;
A very great extent: 7;
Great extent: 5;
Moderate extent: 2;
Some extent: 0;
Little or no extent: 0;
Not sure: 4;
No answer: 29.
e. Another challenge?;
A very great extent: 2;
Great extent: 1;
Moderate extent: 0;
Some extent: 1;
Little or no extent: 0;
Not sure: 4;
No answer: 39.
[End of table]
19. How useful has the overall guidance that OPS has provided on your
IMP inspection roles and responsibilities been?
Extremely useful: 4
Very useful: 23
Moderately useful: 9
Somewhat useful: 5
Not at all useful: 1:
Don't know: 5:
20. A. Have the following sources provided you information or guidance
on conducting gas IMP inspections?
a. OPS State Liaison?;
Yes: 24;
No: 19;
No response: 3.
b. Other OPS Regional Staff?;
Yes: 34;
No: 11;
No response: 2.
c. OPS Training Staff?;
Yes: 40;
No: 6;
No response: 1.
d. National Association of Pipeline Safety Representatives(NAPSR)?;
Yes: 22;
No: 21;
No response: 4.
e. Other source?;
Yes: 14;
No: 1;
No response: 32.
[End of table]
B. Is this a main source of information or guidance on conducting gas
IMP inspections?
a. OPS State Liaison?;
Yes: 7;
No: 34;
No response: 6.
b. Other OPS Regional Staff?;
Yes: 20;
No: 22;
No response: 4.
c. OPS Training Staff?;
Yes: 34;
No: 9;
No response: 4.
d. National Association of Pipeline Safety Representatives(NAPSR)?;
Yes: 5;
No: 33;
No response: 9.
e. Other source?;
Yes: 7;
No: 5;
No response: 35.
[End of Table]
21. Please provide any additional comments that you have in this space.
If your comments are in response to a particular question, please
indicate the question number to which you are referring.
Thank you for completing the survey!
[End of section]
Appendix III: Contact and Staff Acknowledgments:
GAO Contact:
Katherine A. Siggerud (202) 512-2834 or s [Hyperlink,
siggerudk@gao.gov] [Hyperlink, siggerudek@gao.gov] iggerudk@gao.gov:
Staff Acknowledgments:
In addition to the individual named above, Jennifer Clayborne, Tamera
Dorland, Maria Edelstein, Heather Frevert, Cindy Gilbert, Brandon
Haller, John Mingus, and Sara Vermillion made key contributions to this
report.
(542070):
FOOTNOTES
[1] 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. Therefore, our work focused on
natural gas pipelines.
[2] Pipeline agencies in 46 states and the District of Columbia have
this responsibility and, for the purposes of this report, we treat the
agency in the District of Columbia as a state pipeline agency. Two
states do not have state pipeline agencies, and two states do not have
any intrastate gas transmission operators.
[3] In addition to the gas gathering and transmission pipelines, PHMSA
oversees the safety of nearly 1.9 million miles of gas distribution
pipelines and 160,000 miles of hazardous liquid pipelines.
[4] Minimum safety standards for natural gas pipelines are found in 49
C.F.R. part 192; and safety standards for hazardous liquid pipelines
are found in 49 C.F.R. part 195.
[5] Within PHMSA, the Office of Pipeline Safety administers the
national regulatory program to assure the safety of pipelines. Prior to
March 2005, PHMSA was known as the Research and Special Programs
Administration.
[6] P.L. No. 104-304, 110 Stat. 3793 (1996).
[7] PHMSA is currently developing integrity management regulations for
gas distribution pipelines and expects to issue these regulations in
2007.
[8] The measures are in addition to those already required in 49 C.F.R.
part 192 and are specific to the threats that were identified for each
pipeline segment.
[9] According to guidance which PHMSA provided to the states, state
inspectors may use an inspection form or checklist that references the
federal and state regulations.
[10] GAO, Natural Gas Pipeline Safety: Risk-based Standards Should
Allow Operators to Better Tailor Reassessments to Pipeline Threats, GAO-
06-945 (Washington, D.C.: Sept. 8, 2006).
[11] Internal corrosion occurs on the inside of the pipe due to a
chemical attack from something in the pipe, external corrosion occurs
on the outside of the pipe due to environmental conditions, and stress-
corrosion cracking results from stress that causes clusters of cracks
to develop and grow until the pipe fails.
[12] In-line assessment involves running a specialized tool through a
pipeline to detect and record problems, such as corrosion and damage.
Direct assessment is a structured process to integrate information on
the physical characteristics and operating history of a pipeline with
the results of an examination to determine the integrity of the
pipeline.
[13] GAO, Pipeline Safety and Security: Improved Workforce Planning and
Communication Needed, GAO-02-785 (Washington, D.C.: Aug. 26, 2002). We
surveyed the 47 state pipeline agencies about their opinions on
integrity management, their plans for overseeing operator
implementation, and communication with PHMSA.
[14] PHMSA and states do not know the exact number of integrity
management inspections they will have to conduct because multiple
operators may be included under one integrity management program.
[15] Inspections of operators without identified high consequence areas
will be abbreviated and will ensure that the operators correctly made
this determination and have a process to regularly reevaluate their
system to identify any potential new areas that are subject to
integrity management.
[16] GAO, Pipeline Safety and Security: Improved Workforce Planning and
Communication Needed, GAO-02-785 (Washington, D.C.: Aug. 26, 2002).
[17] In addition to integrity management programs, all pipeline
operators are required to have operator qualification programs to
ensure that the individuals who perform certain safety tasks are
qualified to conduct such tasks and public education programs on
pipeline safety issues, such as one-call notification, the hazards of
unintended releases, and the steps to take if there is a release and
the procedure for reporting a release.
[18] GAO, Gas Pipeline Safety: Views on Proposed Legislation to
Reauthorize Pipeline Safety Provisions, GAO-06-1027T (Washington, D.C.:
Aug. 4, 2006).
[19] Texas began inspections in 2001 for the state integrity management
regulations that were in place prior to the federal integrity
management regulations.
[20] We initially sent the survey to pipeline agencies in 48 states,
the District of Columbia and Puerto Rico, however, we excluded two
states (Connecticut and Rhode Island) and Puerto Rico since they did
not have any intrastate gas transmission pipeline operators and
therefore, have no responsibility for conducting these inspections.
Alaska and Hawaii do not have state pipeline agencies, so the survey
was not sent to them.
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