Natural Gas Pipeline Safety: Integrity Management Benefits Public
Safety, but Consistency of Performance Measures Should be	 
Improved (08-SEP-06, GAO-06-946).				 
                                                                 
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.						 
-------------------------Indexing Terms------------------------- 
REPORTNUM:   GAO-06-946 					        
    ACCNO:   A60488						        
  TITLE:     Natural Gas Pipeline Safety: Integrity Management	      
Benefits Public Safety, but Consistency of Performance Measures  
Should be Improved						 
     DATE:   09/08/2006 
  SUBJECT:   Gas pipeline operations				 
	     Hazardous substances				 
	     Industrial safety					 
	     Inspection 					 
	     Natural gas					 
	     Performance measures				 
	     Pipeline operations				 
	     Program management 				 
	     Risk assessment					 
	     Risk management					 
	     Safety standards					 
	     Benefit-cost tracking				 
	     Program costs					 
	     Program implementation				 
	     Public safety					 
	     Gas Integrity Management Program			 
	     OPS Risk Management Demonstration			 
	     Program						 
                                                                 

******************************************************************
** This file contains an ASCII representation of the text of a  **
** GAO Product.                                                 **
**                                                              **
** No attempt has been made to display graphic images, although **
** figure captions are reproduced.  Tables are included, but    **
** may not resemble those in the printed version.               **
**                                                              **
** Please see the PDF (Portable Document Format) file, when     **
** available, for a complete electronic file of the printed     **
** document's contents.                                         **
**                                                              **
******************************************************************
GAO-06-946

     

     * Report to Congressional Committees
          * September 2006
     * NATURAL GAS PIPELINE SAFETY
          * Integrity Management Benefits Public Safety, but Consistency of
            Performance Measures Should Be Improved
     * Contents
          * Results in Brief
          * Background
          * Gas Integrity Management Benefits Public Safety, although
            Operators Have Some Implementation Concerns, and Performance
            Measures Could Be Improved
               * Integrity Management Offers Additional Protection Over
                 Minimum Safety Standards
               * Early Indicators Show That Integrity Management Is
                 Beneficial, Despite Some Operators' Concerns about
                 Implementation
               * Performance Measures Should Show Impact of Integrity
                 Management Over Time, but 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
               * PHMSA Has Developed Tools to Prepare Inspectors for
                 Integrity Management Inspections
               * First Round of Inspections Is Expected to Be Completed by
                 2009 and Initial Inspections Show Operators Are Making Good
                 Progress in Conducting Assessments
          * Conclusions
          * Recommendations for Executive Action
          * Agency Comments and Our Evaluation
     * Scope and Methodology
     * Results of State Pipeline Agency Survey
     * Contact and Staff Acknowledgments

Report to Congressional Committees

September 2006

NATURAL GAS PIPELINE SAFETY

Integrity Management Benefits Public Safety, but Consistency of
Performance Measures Should Be Improved

Contents

Table

Figures

September 8, 2006Letter

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.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.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

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.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.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.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.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.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.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

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.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

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.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   Statistics 
Total miles of pipelines reported                                  296,138 
Total miles of pipelines assessed                                   50,441 
Gas transmission pipelines within high consequence areas:      
Total miles reported                                                20,294 
Total miles assessed                                                 6,707 
Leaksa                                                                 221 
Failuresb                                                               28 
Incidentsc                                                              19 
Immediate repairs completedd                                           340 
Scheduled repairs completede                                         1,981 

Source: PHMSA.

aA leak is an unintentional escape of gas from a pipeline that does not
result in an injury, death, or $50,000 in property damage.

bFailure 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.

cAn 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.

dAn 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.

eScheduled 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.

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.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).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.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 2009.14 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.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.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.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).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 2005.19 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:

o revise the definition of a reportable incident to consider changes in
the price of natural gas and

o 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
http://www.gao.gov.

If you have any questions about this report, please contact me at s 
[email protected] 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.

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

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.1
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.

Appendix II

Results of State Pipeline Agency Survey

Appendix III

Contact and Staff Acknowledgments

GAO Contact

Katherine A. Siggerud (202) 512-2834 or [email protected]

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)

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
[email protected].

Highlights of GAO-06-946 , a report to congressional committees

September 2006

GAS PIPELINE SAFETY

Integrity Management Benefits Public Safety, but Consistency of
Performance Measures Should Be Improved

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 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.

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.

Integrity Management Process for Gas Transmission Pipelines
*** End of document. ***