Natural Gas Pipeline Safety: Risk-Based Standards Should Allow	 
Operators to Better Tailor Reassessments to Pipeline Threats	 
(08-SEP-06, GAO-06-945).					 
                                                                 
The Pipeline Safety Improvement Act of 2002 requires that	 
operators (1) assess gas transmission pipeline segments in about 
20,000 miles of highly populated or frequently used areas by 2012
for safety threats, such as incorrect operation and corrosion	 
(called baseline assessments), (2) remedy defects, and (3)	 
reassess these segments at least every 7 years. Under the	 
Pipeline and Hazardous Materials Safety Administration's (PHMSA) 
regulations, operators must reassess their pipeline segments for 
corrosion at least every 7 years and for all safety threats at	 
least every 10, 15, or 20 years, based on industry consensus	 
standards--and more frequently if conditions warrant. Operators  
must also carry out other prevention and mitigation measures. To 
meet a requirement in the 2002 act, this study addresses how the 
results of baseline assessments and other information inform us  
on the need to reassess gas transmission pipelines every 7 years 
and whether inspection services and tools are likely to be	 
available to do so, among other things. In conducting its work,  
GAO contacted 52 operators that have carried out about two-thirds
of the baseline assessments conducted to date.			 
-------------------------Indexing Terms------------------------- 
REPORTNUM:   GAO-06-945 					        
    ACCNO:   A60487						        
  TITLE:     Natural Gas Pipeline Safety: Risk-Based Standards Should 
Allow Operators to Better Tailor Reassessments to Pipeline	 
Threats 							 
     DATE:   09/08/2006 
  SUBJECT:   Corrosion						 
	     Federal law					 
	     Gas pipeline operations				 
	     Program evaluation 				 
	     Risk assessment					 
	     Safety regulation					 
	     Safety standards					 
	     Strategic planning 				 

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GAO-06-945

     

     * Report to Congressional Committees
          * September 2006
     * NATURAL GAS PIPELINE SAFETY
          * Risk-Based Standards Should Allow Operators to Better Tailor
            Reassessments to Pipeline Threats
     * Contents
          * Results in Brief
          * Background
          * The 7-Year Reassessment Requirement Appears to Be Conservative
               * Most Operators Have Reported That Their Gas Transmission
                 Pipelines Are Mostly Free of Serious Problems
               * Operators Support Baseline Assessments and Reassessments but
                 Prefer a Risk-based Reassessment Requirement Over a Fixed
                 One
               * Safeguards Exist if Industry Consensus Standards for
                 Corrosion Reassessments Are Allowed
          * Sufficient Resources May Be Available for Pipeline Reassessments
               * Operators Report that Services and Tools Are Likely to Be
                 Available for Reassessments
               * The Amount of Assessment Activity Occurring in the Overlap
                 Period Is Uncertain
          * Conclusions
          * Matter for Congressional Consideration
          * Agency Comments and Our Evaluation
     * Impact of Periodic Reassessments on Natural Gas Supply May Be Less
       than Foreseen
          * INGAA Study Expected Significant Supply Disruptions and Price
            Increases
          * PHMSA-commissioned Reviews and PHMSA's Regulatory Evaluation
            Predict More Moderate Impacts
          * Operators Contacted Found Assessments Have Had Minimal Impact on
            Supply
          * Post-act Industry Polling Found Members Plan to Modify and Repair
            Pipelines, Which May Affect Natural Gas Supply
          * Department of Energy Expects Little Disruption in the Natural Gas
            Supply
     * Scope and Methodology
          * Other Aspects of Our Work
          * Organizations Contacted
     * Contact and Staff Acknowledgments

Report to Congressional Committees

September 2006

NATURAL GAS PIPELINE SAFETY

Risk-Based Standards Should Allow Operators to Better Tailor Reassessments
to Pipeline Threats

Contents

Figures

September 8, 2006Letter

Congressional Committees:

Gas transmission pipelines are one of the nation's safest modes of freight
transportation: nationwide about three people have died and about eight
have been injured annually, on average, over the past decade because of
natural gas pipeline incidents from all causes.1 To enhance the safety of
gas transmission pipelines, the Pipeline Safety Improvement Act of 2002
requires that operators of these pipelines develop programs to assess and
mitigate safety threats, such as leaks or ruptures due to incorrect
operation or corrosion, to pipeline segments that are located in highly
populated and frequently used areas, such as parks. Specifically,
operators are required to perform baseline assessments on one-half of the
gas transmission pipeline mileage located in these areas by December 2007
and the remainder by December 2012. Pipeline segments that potentially
face the greatest risks of failure from leaks or ruptures are to be
assessed first.

The 2002 act also requires that operators reassess these pipeline segments
for safety threats at least every 7 years. Under flexibility provided by
the act, the federal regulator-the Pipeline and Hazardous Materials Safety
Administration (PHMSA)-requires that operators reassess these pipeline
segments for corrosion damage at least every 7 years in its implementing
regulations, because corrosion is the most frequent cause of failures that
can occur over time.2 It also incorporated, as mandatory, voluntary
industry consensus standards on maximum reassessment intervals into these
regulations for other types of safety threats. The industry standards
require that operators reassess gas pipelines at least every 10, 15, or 20
years for all safety risks, depending primarily on the condition of the
pipelines and the pressure under which they operate. If conditions
warrant, reassessments must occur more frequently.

The 2002 act required that we assess the 7-year reassessment requirement.
To do so, we examined (1) the extent to which findings from baseline
assessments and other information inform us about the need to reassess gas
transmission pipelines for safety risks at least every 7 years and (2) the
ability of operators to obtain the services and tools needed to perform
the reassessments. These two topics are the main focus of this report. We
also examined the potential impact of periodic assessments on the nation's
natural gas supply. (See app. I.) This report deals mostly with natural
gas transmission pipelines, which represent the overwhelming majority of
gas pipelines.3

To understand how the findings from operators' baseline assessments and
other information inform us about the need to reassess gas transmission
pipelines at least every 7 years, we reviewed laws, regulations, and other
PHMSA guidance. We discussed this issue with PHMSA, other federal
agencies, industry associations, companies that perform research in this
area, state safety representatives, and safety advocacy groups. We also
obtained information from 52 gas pipeline operators for which baseline
assessments and reassessments could have the greatest impact, all else
being equal: larger and smaller transmission pipelines and local
distribution companies (pipeline companies that take gas from transmission
pipelines and distribute it to end users) with the highest proportion of
pipeline miles in highly populated and frequently used areas to total
system miles. Overall, these operators have assessed about 21 percent of
the 20,000 miles of gas transmission pipeline that operators have reported
as being within highly populated or frequently used areas.4 In addition,
we analyzed data from PHMSA for 241 operators that reported, in 2004 and
2005, on the number of immediate repairs conducted after completing their
baseline assessments.5 To determine the extent to which gas transmission
pipeline operators and local distribution companies will likely have the
resources to reassess their pipelines at least every 7 years, we asked
operators, inspection tool contractors, and industry associations about
the availability of equipment, equipment operators, and data analysts to
interpret results. We also synthesized the information from the 52
operators to determine the aggregate level of actual and planned
assessments and reassessments through 2012 and compared our findings with
the results from an Interstate Natural Gas Association of America and
American Gas Association data collection effort on the same topic. As part
of our work, we assessed the internal controls and the reliability of the
data elements needed for this engagement, and we determined that the data
elements were sufficiently reliable for our purposes. We performed our
work between August 2005 and August 2006 in accordance with generally
accepted government auditing standards. (See app. II for additional
details on our scope and methodology.)

Results in Brief

Periodic reassessments of pipeline threats are beneficial because
threats-such as the corrosive nature of the gas being transported-can
change over time. Baseline assessment findings conducted to date and the
generally safe condition of gas transmission pipelines, suggest that the
7-year reassessment requirement appears to be conservative. Through
December 2005 (latest data available), 76 percent of the operators (182 of
241) reporting baseline assessment activity reported to PHMSA that their
gas transmission pipelines were in good condition and free of major
defects, requiring only minor repairs. (See fig. 1.) Most of the 340
problems reported were concentrated in just seven pipelines.6 (These
assessments reported by the 241 operators covered about 6,700 miles, or
about one-third of the nationwide total to be assessed by 2012.) Because
PHMSA does not require operators to identify the nature of the problems,
we do not know how many, if any, were corrosion related.

Figure 1: Most Operators Reported That Their Gas Transmission Pipelines
Are in Good Condition, as of December 2005

Note: Results of 241 operators that reported to PHMSA that they completed
6,700 miles of baseline assessments. Of those operators that reported no
problems, 82 operate smaller pipeline systems (1 to 49 miles), 41 operate
mid-sized systems (50 to 199 miles) and 59 operate larger systems (200 or
more miles).

These results are encouraging, since operators are required to assess
their riskiest segments first and 54 percent of the operators we contacted
that have begun baseline assessments told us that they had not conducted
risk-based assessments before the onset of the gas integrity management
program. This suggests that, overall, operators that have thus performed
baselines assessments are doing a good job in managing corrosion.
Furthermore, since operators are required to repair these gas transmission
pipelines the overall safety and condition of the pipeline system should
be improved before reassessments begin toward the end of the decade. In
addition, PHMSA data show corrosion incidents are rare: over the past
5-1/2 years (from January 2001 through early July 2006), there were 26
corrosion-related incidents over the 295,000-mile transmission system per
year, on average-none of which resulted in death or injury.7

Of the 52 operators that we contacted, 23 have calculated reassessment
intervals. Based on conditions identified during baseline assessments, 20
of these 23 operators indicated that they would reassess their gas
transmission pipelines at the maximum allowable intervals prescribed by
industry consensus standards-if the 7-year reassessment requirement were
not in place.8 Most operators we contacted (42 of 52 or 81 percent) told
us that they prefer following industry consensus standards that base
reassessment intervals on the characteristics and conditions of pipelines
and that were developed using historical information and research.
Although the industry consensus standards recognize that corrosion does
not occur at a rapid rate, they allow for maximum reassessment intervals
for time-dependent threats of 10, 15, or 20 years only if the operator can
adequately demonstrate that corrosion will not become a threat within the
chosen time interval. If not, then the reassessment must occur more
frequently, perhaps at 7 or even fewer years. Federal policy encourages
the use of industry consensus standards, and PHMSA's implementing
regulations incorporate three other industry consensus standards.

PHMSA and state pipeline agencies are conducting inspections that should
serve as a check as to whether operators have identified threats facing
these gas transmission pipeline segments and have determined appropriate
reassessment intervals. Initial results from 137 federal and state
inspections show that operators are doing well on assessing their
pipelines and making repairs. PHMSA and state agencies plan to inspect all
operators' compliance with integrity management, including reassessment
requirements and complete most of them by 2009 to, among other things,
ensure that operators continually and appropriately assess the conditions
of their pipeline segments. Finally, basing reassessments for corrosion on
risk would be consistent with the risk-based approach to improving
pipeline safety (called integrity management) set out in the 2002 act. We
recently reported that PHMSA's implementation of the gas integrity
management program is designed to enhance public safety.9

Sufficient resources may be available for operators to reassess their gas
transmission pipelines, but some uncertainty exists. For the most part,
the 52 operators and four inspection contractors we contacted told us that
services and tools needed to conduct assessments have been readily
available for baseline assessments, and they do not anticipate
difficulties obtaining these resources in the future. Operators that
reported both baseline and reassessment schedules told us they plan to
reassess 42 percent of their pipeline miles in highly populated or
frequently used areas using in-line inspection.10 Operators we contacted
said that the in-line inspection industry is well established and has the
capacity to expand readily. Operators plan to use direct assessment or
confirmatory direct assessment methods in reassessing another 54 percent
of their pipeline miles.11 However, they told us that expertise in direct
assessment methods is limited; therefore, they may not be as readily
available to all operators. Industry associations and we asked operators
to estimate the number of miles of gas transmission pipeline they planned
to assess through 2012 in order to determine whether an increase in
overall assessment activity would occur because of the overlap between
completing baseline assessments and beginning reassessments from 2010
through 2012. The results were conflicting: the industry found an increase
in activity, while we found a decrease. The reasons for these contrasting
findings are unclear but may be due, in part, to the difference in methods
used in collecting this information.

We suggest that the Congress amend the Pipeline Safety Improvement Act of
2002 to permit pipeline operators to reassess their gas transmission
pipeline segments at intervals based on risk factors, technical data, and
engineering analyses. Such a revision would allow PHMSA to establish
maximum reassessment intervals, and to require shorter reassessment
intervals as conditions warrant.

In commenting on a draft of this report, the Department of Transportation
generally agreed with the report's findings. The Department of Energy had
no comments.

Background

The United States has about a 295,000-mile network of gas transmission
pipelines that are owned and operated by approximately 900 operators.
These pipelines are important to the nation because they transport nearly
all the natural gas used, which provides about a quarter of the nation's
energy supply. Pipelines do not experience many of the safety threats
faced by other forms of freight transportation because they are mostly
underground; but they are subject to failures that occur over time-such as
leaks and ruptures resulting from corrosion12 or welding defects-and
failures that are independent of time-such as damage from excavation, land
movement, or incorrect operation.

For the most part, two types of pipelines transport gas products: (1) gas
transmission pipelines and (2) local distribution pipelines. Gas
transmission pipelines typically move gas products over long distances
from sources to communities and are primarily interstate. They typically
operate at a higher stress level (higher operating pressure in relation to
wall strength). By contrast, local distribution pipelines receive gas from
transmission pipelines and distribute it to commercial and residential end
users. Local distribution pipelines, which are primarily intrastate,
typically operate under lower-stress conditions. Local distribution
companies may also operate small portions of transmission
pipelines-typically under lower stress-and are therefore subject to the
assessment and reassessment requirements of the Pipeline Safety
Improvement Act of 2002.13

Before the 2002 act, operators were subject to PHMSA's minimum safety
standards for the design, construction, testing, inspection, operation,
and maintenance of gas transmission pipelines; these standards are applied
to all pipelines. However, this approach does not account for differences
in the kinds of threats and the degrees of risk that pipelines face. For
example, pipelines located in the Pacific Northwest are more susceptible
to damage from geologic hazards, such as land movement, than pipelines in
some other areas of the country; but PHMSA's safety standards do not take

these threats into account in a systematic way.14 By contrast, the
risk-based approach of the 2002 act-called the integrity management
approach-requires pipeline operators to develop programs to systematically
identify threats and mitigate risks to gas transmission pipeline segments
located in highly populated or frequently used areas.15 In addition to
PHMSA's integrity management program, operators must still meet the
minimum safety standards.

As of December 2005 (latest data available), 447 gas pipeline operators
reported to PHMSA that about 20,000 miles of their pipelines (about 7
percent of all gas transmission pipeline miles) lie in highly populated or
frequently used areas. Individual operators reported that they have as
many as about 1,600 miles and as few as 0.02 miles of transmission
pipeline in these areas.

Under PHMSA's regulations, gas pipeline operators may use any of three
primary approaches to conduct baseline assessments on pipeline segments
lying in highly populated or frequently used areas.

o In-line inspection: In-line inspection involves running a specialized
tool through the pipeline to detect and record anomalies, such as metal
loss and damage. In-line inspection allows operators to determine the
nature of any problems without either shutting down the pipeline for
extended periods or potentially damaging the pipeline, as in hydrostatic
testing (described below). In-line inspection devices can be run only from
facilities established for launching and retrieving them. These launching
and retrieval locations may extend beyond highly populated or frequently
used areas. Operators will typically gather information along the entire
distance between launching and retrieval locations to gain additional
safety information; this is called over-testing.

o Direct assessment: Direct assessment is a nonintrusive, above-ground
instrument inspection that uses two or more types of diagnostic tools,
such as a close interval survey, at predetermined intervals along the
pipeline.16 Once the data are analyzed, the operator excavates and
inspects segments of the pipeline suspected to have safety threats.

o Hydrostatic testing: Hydrostatic testing entails sealing off a portion
of the pipeline, removing the gas product, filling it with water, and
increasing the pressure of the water above the rated strength of the
pipeline to test its integrity. If the pipeline leaks or ruptures, the
pipeline is excavated to determine the cause of the failure. Operators
must shut down pipelines to perform hydrostatic testing. Also, this form
of testing can damage the pipeline due to high pressure testing. Finally,
operators must be able to dispose of large quantities of water in an
environmentally responsible manner.

Under PHMSA's regulations, which incorporate voluntary industry consensus
standards for managing the system integrity of gas pipelines,17 operators
must reassess their gas transmission pipeline segments for safety threats
overall at least every 10, 15, or 20 years (consistent with industry
consensus standards), depending on the condition of the pipelines and the
stress under which the pipeline segments are operated. PHMSA's regulations
allow operators to limit the statutorily required 7-year reassessment to
corrosion damage. In performing reassessments to meet the 7-year
requirement, operators may employ a technique called confirmatory direct
assessment. This technique is similar to direct assessment; however,
operators are required to use only one type of assessment tool, rather
than at least two types required under direct assessment. According to
PHMSA, it allowed this more limited assessment because the 7-year
reassessment for corrosion confirms the acceptable integrity of a gas
transmission pipeline, already ensured by assessments and reassessments
for safety threats conducted at 10-, 15-, or 20-year intervals under the
industry consensus standards incorporated in the agency's regulations.
(See fig. 2.) About 2010, operators will be expected to begin reassessing
some segments of their pipelines for corrosion under the 7-year
reassessment requirement while they are completing baseline assessments of
other segments-called "the overlap."

Figure 2: Reassessments Every 7 Years for Corrosion Supplement Broader
Periodic Reassessments

Note: Periodic reassessments occur at least every 10, 15, or 20 years.
Both periodic and 7-year reassessments are supposed to occur more
frequently if conditions warrant.

It is important to note that the reassessment intervals under the industry
consensus standards, the 7-year reassessment requirement for corrosion,
and PHMSA's regulations for time-dependent threats represent the maximum
number of years between reassessments. If pipeline conditions dictate more
frequent reassessments-for example, 5 or fewer years-then pipeline
operators must do so to comply with PHMSA's regulations.18 In addition,
between reassessments, operators must continually ensure that their gas
transmission pipelines are safe. PHMSA's regulations require all
operators-whether or not they are located in highly populated or
frequently used areas to patrol their pipelines, survey for leakage,
maintain valves, ensure that corrosion-preventing cathodic protection is

working properly,19 and take prevention and mitigation measures to prevent
excavation damage.

PHMSA, within the Department of Transportation, attempts to ensure the
safe operation of pipelines through regulation, industry consensus
standards, research, education (e.g., to prevent excavation-related
damage), oversight of the industry through inspections, and enforcement,
when safety problems are found. PHMSA employs about 165 people in its
pipeline safety program, about half of whom are pipeline inspectors who
inspect operators' implementation of integrity management programs for gas
and hazardous liquid (e.g., oil, gasoline, and anhydrous ammonia)
pipelines, in addition to other more traditional compliance programs.
PHMSA currently has 22 inspectors trained to conduct integrity management
inspections, of which 9 are devoted exclusively to the program. In
addition, PHMSA expects to be assisted by about 180 inspectors in 46
states and the District of Columbia in overseeing intrastate natural gas
transmission pipelines.

The 7-Year Reassessment Requirement Appears to Be Conservative

Periodic reassessments of pipeline threats are beneficial because
threats-such as the corrosive nature of the gas being transported-can
change over time. Baseline assessment findings conducted to date and the
generally safe condition of gas transmission pipelines suggest that the
7-year requirement appears to be conservative. Most operators of gas
transmission pipelines reported to PHMSA that their baseline assessments
have disclosed 340 problems for which immediate repairs have been made.
This is encouraging because these pipeline segments are supposed to be the
riskiest and few have been systematically assessed until now. Regarding
the industry safety record, the industry is generally safe and no
corrosion-related incidents resulting in deaths or injuries have occurred
in the past 5-1/2 years (from January 2001 through early July 2006)
anywhere in the nation, let alone in highly populated or frequently used
areas.20 It is therefore likely to be safe in most cases to allow longer
maximum intervals that coincide with industry consensus standards. PHMSA
and state pipeline agencies plan to inspect all operators' integrity
management activities, which should serve as a safeguard if longer
reassessment intervals for corrosion are permitted.

Most Operators Have Reported That Their Gas Transmission Pipelines Are
Mostly Free of Serious Problems

Through December 2005 (latest data available), 76 percent of the operators
(182 of 241) reporting baseline assessment activity to PHMSA told the
agency that their gas transmission pipelines were in good condition and
free of major defects, requiring only minor repairs. (These assessments
covered about 6,700 miles, or about one-third of the nationwide total to
be assessed). The remaining 59 operators reported 340 problems for which
immediate repairs have been completed. (See fig. 1.)

Fifty-two operators (21 percent) reported nine or fewer problems for which
immediate repairs have been completed; and seven operators (3 percent)
reported 10 or more problems. Most of the problems stem from the seven
operators reporting 10 or more problems and concern only a small portion
of their gas transmission pipelines. Specifically, these seven operators
represent nearly 60 percent of the total problems requiring immediate
repairs, and the problems occurred in only 7 percent of 6,700 miles of
baseline assessments conducted.21 Since PHMSA does not require that
operators report to it the nature of the problems, we do not know how many
of the 340 problems, if any, were due to corrosion.

We contacted 52 operators about the baseline assessments they have
completed and their plans for the rest, and the results were largely
consistent with the overall data reported to PHMSA. Forty-four of these
operators have begun baseline assessments, and 37 of these 44 (84 percent)
told us that they found few safety problems that required reducing
pipeline pressure and performing immediate repairs in response to baseline
assessments in highly populated or frequently used areas. These 44
operators have assessed about 4,100 miles of gas transmission pipeline,
representing about 61 percent of the 6,700 miles of baseline assessment
results reported to PHMSA and about 21 percent of the total number of
pipeline miles in highly populated or frequently used areas nationwide.

It is encouraging that the majority of operators nationwide reported few
or no problems involving immediate repairs, because (1) operators are to
assess pipeline segments facing the greatest risk of failure from leaks or
ruptures first, as required by the 2002 act, and (2) 54 percent of the
operators we contacted (28 of 52) had not conducted risk-based assessments
of their pipeline segments for safety threats prior to the integrity
management program.

Although the PHMSA regulations focus the 7-year reassessment requirement
on corrosion because it is the most frequent cause of time-dependent
pipeline incidents,22 the industry has had a good safety record prior to
and during the initial years of integrity management. It is not possible
to determine which incidents occurred in highly populated or frequently
used areas from summary historical data published by PHMSA. However,
nationwide, these incidents are relatively rare. Over the past 5 1/2 years
(from January 2001 through early July 2006), there were 143
corrosion-related incidents over the 295,000-mile transmission system (26
per year, on average)-none of which resulted in death or injury. In
addition, according to PHMSA, during the first 2 years of integrity
management (2004 and 2005), operators reported that corrosion caused 49
leaks,23 16 failures, and two incidents involving significant property
damage, but no fatalities and injuries, in highly populated or frequently
used areas.

Both the positive results found during baseline assessments conducted to
date and the overall good safety industry record suggest that gas
transmission pipeline operators that have thus far performed baseline
assessments overall are doing a good job in managing corrosion. Further,
since operators, are required to identify and repair significant problems,
the overall safety and condition of the gas transmission pipeline system
should be enhanced before reassessments begin toward the end of the
decade.

Operators Support Baseline Assessments and Reassessments but Prefer a
Risk-based Reassessment Requirement Over a Fixed One

Because many gas transmission pipelines had never been assessed before
integrity management, operators we contacted pointed out that the new
knowledge gained through baseline assessments represents one of the
greatest benefits of the integrity management program. They also support
reassessments, in part because all operators are subject to the same
requirements. However, most support a risk-based reassessment requirement,
consistent with overall integrity management, over the fixed 7-year
requirement prescribed by the 2002 act. Operators also told us they prefer
a risk-based reassessment requirement that is based on research and
historical information. Most operators told us they prefer reassessing
pipelines based on the characteristics and conditions of the pipeline
rather than on the 7-year requirement prescribed in the 2002 act. About 80
percent of the 52 operators that we contacted prefer that reassessment
intervals be based on the condition and characteristics of the pipeline
segment. About half of these operators (28) expressed a preference for the
industry consensus standard developed by the American Society of
Mechanical Engineers (ASME B31.8S-2004) for setting reassessment intervals
for time-dependent threats because it incorporates a risk-based approach
(for pipeline failure) and is based on science and engineering knowledge.
This standard sets reassessment intervals at a maximum of 10 years for
high-stress pipeline segments, 15 years for medium-stress segments, and 20
years for low-stress segments. Maximum reassessment intervals, such as
those in the industry consensus standard, incorporate such risk concepts
as built-in safety factors (e.g., wall stress, test pressure, or predicted
failure) and pipeline conditions. The maximum intervals of 10, 15, and 20
years are based on worst-case corrosion growth rates.

The industry consensus standards were developed in 2001 and updated in
2004 based on, among other things, (1) the experience and expertise of
engineers, consultants, operators, local distribution companies, and
pipeline manufacturers; (2) more than 20 technical studies conducted by
the Gas Technology Institute, ranging from pipeline design factors to
natural gas pipeline risk management; and (3) other industry consensus
standards, including the National Association of Corrosion Engineers
standards, on topics such as corrosion. Contributors have been practicing
aspects of risk-based assessments for over 10 years. This standard serves
as a foundation for most sections of PHMSA's integrity management
regulations. The mechanical engineering society's standard was reviewed

by the American National Standards Institute.24 The institute found that
the standard was developed in an environment of openness, balance,
consensus, and due process and therefore approved it as an American
National Standard.

While the mechanical engineering standards are voluntary for the industry,
PHMSA incorporated them as mandatory in its gas transmission integrity
management regulations. The mechanical engineering society's standard for
setting reassessment intervals is not the only industry consensus standard
in PHMSA's integrity management regulations. The regulations incorporate
other industry consensus standards for using direct assessment for
corrosion, calculating pipeline wall strength, and for determining
temporary reductions in operating pressure. In addition, it is federal
policy to encourage the use of industry consensus standards: the Congress
expressed a preference for technical standards developed by consensus
bodies over agency-unique standards in the National Technology Transfer
and Advancement Act of 1995. The Office of Management and Budget's
Circular A-119 provides guidance to federal agencies on the use of
voluntary consensus standards, including the attributes that define such
standards.

Of the 52 operators we contacted, 44 had undertaken baseline assessments,
and 23 of the 44 have calculated their own reassessment intervals.25
Twenty of these 23 operators indicated that, based on the conditions they
identified during their baseline assessments, they would reassess their
gas transmission pipelines at maximum intervals of 10, 15, or 20 years-as
allowed by industry consensus standards-if the 7-year reassessment
requirement were not in place. The remaining three operators told us that
they would reassess their pipelines at intervals shorter than the industry
consensus standards but longer than 7 years because of the conditions of
their pipelines. These results add weight to our assessment that the
7-year requirement may be conservative for most pipelines.

Safeguards Exist if Industry Consensus Standards for Corrosion
Reassessments Are Allowed

Industry consensus standards allow for maximum reassessment intervals for
time-dependent threats of 10, 15, or 20 years only if the operator can
adequately demonstrate that corrosion will not become a threat within the
chosen time interval. If an operator cannot demonstrate that corrosion
does not pose a threat, (e.g., threats posed by shipping gas that is more
corrosive then was shipped previously), then the reassessment must occur
sooner, perhaps at 7 or even 5 or fewer years. Furthermore, according to
industry consensus standards, it typically takes longer than the 10, 15,
or 20 years specified in the standard for corrosion problems to result in
a leak or rupture.

As a means of ensuring that assessments and reassessments are done
competently, PHMSA regulations and industry consensus standards require
that operators develop and document the steps they take to ensure the
quality of these activities. This includes ensuring that persons involved
are competent and able to carry out the activities. In addition, operators
are encouraged to conduct internal audits of their quality control
approaches and third-party reviews of their entire integrity management
programs.

It is important to note that, in addition to periodic reassessments,
operators must perform prevention and mitigation activities on a continual
basis. PHMSA regulations require that all operators of gas transmission
pipelines, including those outside highly populated or frequently used
areas, patrol their pipelines, survey for leakage, maintain valves, ensure
that corrosion-preventing cathodic protection is working properly, and
take other prevention and mitigation measures.

Finally, PHMSA and the state pipeline agencies are inspecting operators'
integrity management plans that were mandated by the 2002 act to provide
their gas transmission pipeline reassessment approaches and intervals,
among other things, to ensure that operators continually and appropriately
assess the conditions of their pipeline segments in highly populated or
frequently used areas. These inspections should serve as a check on
whether operators have identified threats facing these pipeline segments
and determined appropriate reassessment intervals. PHMSA and states have
begun inspections and expect to complete most of the first round no later
than 2009. As of June 2006, PHMSA had completed 20 of about 100
inspections and, as of January 2006, states had begun or had completed 117

of about 670 inspections.26 Initial results from these inspections show
that operators are doing well in assessing their pipelines and making
repairs, but some need to better document their programs. Based on the
initial inspection results to date, PHMSA and states did not find many
issues that warranted enforcement actions.

Sufficient Resources May Be Available for Pipeline Reassessments

Although some uncertainty exists, sufficient resources may be available
for operators to reassess their gas transmission pipelines. Operators and
inspection contractors we contacted told us that the services and tools
needed to conduct periodic reassessments will likely be available to most
operators. However, operators expressed their uncertainty about whether
qualified direct assessment and confirmatory direct assessment contractors
will be available. This is important because operators plan to use these
methods to reassess about half of their pipeline mileage.

Contractors told us that they will likely have the capacity to meet
demands, even during periods when baseline assessments and reassessments
may overlap. The severity of this overlap, however, remains unclear.
Although operators that we contacted expect baseline assessment and
reassessment activity to decrease from 2010 through 2012, an Interstate
National Gas Association of America (INGAA) and American Gas Association
(AGA) polling of their members suggests that activity will rise
markedly.27

Operators Report that Services and Tools Are Likely to Be Available for
Reassessments

Thirty-seven out of 52 operators (71 percent), one in-line inspection
association, and all four inspection contractors that provide direct
assessment or in-line inspection tool services that we contacted told us
that the services and tools needed to conduct periodic reassessments will
likely be available to most operators.28 All but 3 of the operators
reported that they plan to rely on contractors to conduct all or a portion
of their reassessments, and 9 of 52 operators have signed, or would like
to sign, long-term contracts that extend contractor services through a
number of years. However, few have scheduled reassessments with
contractors, as they are several years in the future and operators are
concentrating on baseline assessments.

The 48 operators that reported both baseline and reassessment schedules
told us that they plan to reassess 42 percent of their gas transmission
pipeline miles in highly populated or frequently used areas, using in-line
inspection, and 54 percent of their miles using direct assessment or
confirmatory direct assessment methods.29 (See fig. 3.) Operators expect
to assess only 4 percent of their pipeline miles using hydrostatic testing
for several reasons: (1) this form of testing requires shutting down their
pipelines, (2) other assessment methods yield more robust information
about the condition of their pipelines, (3) hydrostatic testing can weaken
or damage pipelines, and (4) large quantities of water must be disposed of
in an environmentally responsible manner.

Figure 3: Operators Contacted Plan to Reassess Nearly All of the Mileage
in Highly Populated or Frequently Used Areas Using In-line Inspection and
Direct Assessment Tools

Note: Some operators may use one type of assessment tool on one portion of
their gas transmission pipeline and another type of assessment tool on
another portion.

The Inline Inspection Association and the two in-line inspection
contractors that we contacted told us that sufficient capacity exists
within the industry to meet current and future operator demands. However,
operators and inspection contractors expressed uncertainty about whether
qualified direct assessment and confirmatory direct assessment contractors
will be available. This is important because operators plan to use these
methods to reassess about half of their gas transmission pipeline mileage.
Unlike the in-line inspection method, which is an established and less
intrusive practice that 27 of 52 operators have used on their pipelines at
least once prior to the integrity management program, two direct
assessment contractors told us that there is limited expertise in this
field. One said that newer contractors coming into the market to meet
demand may not be qualified. The operators planning to use direct
assessment for their pipelines are generally those with smaller-diameter
pipelines that

cannot accommodate in-line inspection tools.30 At a recent INGAA integrity
management workshop, in-line inspection and direct assessment inspection
contractors emphasized that, although they currently have the resources to
meet operator demand and continue to train new inspectors, operators need
to plan ahead to ensure resource availability for future years, when
resources may be more constrained. The workshop also highlighted
technological developments for assessment tools that will make assessments
more efficient. Other stakeholders have told us that there are new tools
being developed that will enable smaller-diameter pipelines to accommodate
in-line inspection tools. For example, the Department of Energy is
developing tiny robotic sensors that can detect flaws in plastic natural
gas pipelines without interrupting the flow of gas.

The Amount of Assessment Activity Occurring in the Overlap Period Is
Uncertain

An industry concern about the 7-year reassessment requirement is that
operators will be required to conduct reassessments starting no later than
2010, while they are still in the 10-year period (2003 through 2012) for
conducting baseline assessments. Industry is concerned that this could
create a spike in demand for contractor services, and operators would have
to compete for the limited number of contractors to carry out both. As a
result, operators might not be able to meet the reassessment
requirement.31 The information provided by the operators that we contacted
shows a marked overall increase in assessment and reassessment activity in
2010 (a 16 percent increase over 2009 activity) and then a gradual
decrease of activity through 2012. (See fig. 4.) Operators expect this
decrease because they plan to have completed a large number of baseline
assessments between 2005 and 2007 in order to meet the statutory deadline
for completing at least half of their baseline assessments by December
2007 (3 years before the predicted overlap).

Figure 4: Baseline Assessment and Reassessment Activities Are Expected to
Decrease during the Overlap Period, According to Operators We Contacted

Note: These results are based on information obtained from 47 of 52
operators we contacted, covering 154,000 miles of gas transmission
pipeline, 12,000 miles of which are in highly populated or frequently used
areas. Five operators did not report their reassessment plans. We did not
ask operators to separate baseline assessments and reassessments in areas
that are not highly populated or frequently used.

In contrast, INGAA and AGA, after polling their members in 2006, found a
steady overall increase in total expected baseline assessments and
reassessments during the overlap period. INGAA and AGA found that baseline
assessments and reassessments would start to increase in 2009 and rise
steadily through 2012.32 (See fig. 5.) Assessment activity would increase
by 5 percent in 2010 over the 2009 level; in 2011, by 8 percent over the
preceding year; and in 2012, by 10 percent over the 2011 level.

Figure 5: Baseline and Reassessment Activities Are Expected to Increase
during the Overlap Period, According to INGAA and AGA

Note: These results are based on responses from 56 operators covering
180,000 miles of gas transmission pipeline, 11,000 miles of which are in
frequently used or highly populated areas.

The difference between our findings and those of INGAA and AGA is not easy
to explain. (See fig. 6.) Both efforts reported on comparable numbers of
operators (47 for us and 56 for INGAA/AGA) and total transmission pipeline
miles (154,000 for us and 180,000 for INGAA/AGA). To some extent, the
difference may be due to the variations in the pipeline operators that
responded to both efforts. About 72 percent of operators we polled were
different from those polled by INGAA and AGA. However, even where both
efforts collected information from the same operators, the information was
sometimes markedly different. Another reason for the difference may be due
to methodology. For example, we gathered our information through
semistructured interviews with a systematically selected set of pipeline
operators based on larger and smaller transmission pipelines and local
distribution companies with the highest proportion of pipeline miles in
highly populated or frequently used areas to total system miles, among
other things. INGAA and AGA gathered their information by sending out a
self-administered data collection instrument to their members, and
reported results based on those members who responded. In addition, INGAA
and AGA asked operators for data somewhat differently from methods we
used, which may have led to some differences in results.

Figure 6: GAO and INGAA/AGA Results Show Different Trends in Assessment
Activity during the Overlap Period

Note: See text for possible reasons for the difference in results. Readers
should not interpret these results to suggest that operators are not
planning to complete all required baseline assessment activities by the
end of 2012.

Conclusions

Evidence as a result of baseline assessments, the industry's overall
safety record, the existence of accepted risk-based assessment standards,
and PHMSA's actions to inspect how operators are identifying corrosion
threats to their pipelines and setting reassessment intervals suggests a
risk-based approach to reassessing gas transmission pipeline segments for
corrosion can achieve the safety objectives of the 2002 act. Evidence
gathered to date suggests that operators that have thus performed baseline
assessments are doing a good job overall managing corrosion. Since the
large majority of pipeline operators that we contacted had not
systematically assessed their transmission pipelines for corrosion risks
before the onset of the gas integrity management program, if corrosion
were a rapidly growing problem, we would have expected a larger proportion
of pipelines to report problems requiring immediate repairs. But, this was
not the case. Furthermore, adopting a risk-based approach to setting
reassessment intervals does not automatically allow operators to reassess
their pipeline segments less frequently than under the 7-year requirement.
Rather, if conditions warrant, an operator would be required to reassess a
pipeline segment as frequently as needed-perhaps even more frequently than
every 7 years. Finally, a risk-based reassessment requirement would be
consistent with the overall approach to integrity management that the
Congress put in place with the 2002 act.

Safeguards are in place to ensure that gas transmission operators
determine reassessment intervals competently. PHMSA regulations and
industry consensus standards require that operators ensure that persons
involved have the experience and expertise to carry out the activities.
Operators are also encouraged to conduct internal audits of their quality
control approaches and third-party reviews of their integrity management
programs. PHMSA and the state pipeline agencies are inspecting operators'
compliance with integrity management reassessment requirements, among
other things, to ensure that operators continually and appropriately
assess the conditions of their gas transmission pipeline segments in
highly populated or frequently used areas.

In summary, the available evidence supports a conclusion that a risk-based
reassessment approach based on technical data, risk factors, and
engineering analyses can achieve the 2002 act's safety objectives. Such an
approach would provide for reassessments to be tailored to the corrosion
threats faced by the pipeline segment and would not result in
reassessments that are either too infrequent or premature. Evidence to
date suggests that gas transmission pipelines are generally in good shape
based on assessments, following up with immediate repairs and safeguards
being in place to ensure operators determine reassessments appropriately.
In our view, it is not necessary to wait until baseline assessments and a
round of reassessments have been completed before considering whether to
retain or modify the 7-year reassessment requirement.

Matter for Congressional Consideration

To better align reassessments with safety risks, the Congress should
consider amending section 14 of the Pipeline Safety Improvement Act of
2002 to permit pipeline operators to reassess their gas transmission
pipeline segments at intervals based on technical data, risk factors, and
engineering analyses. Such a revision would allow PHMSA to establish
maximum reassessment intervals, and to require shorter reassessment
intervals as conditions warrant.

Agency Comments and Our Evaluation

We provided a draft of this report to the Departments of Transportation
and Energy for their review and comment. The Department of Transportation
generally agreed with the report's findings. The Department of Energy had
no comments.

We are sending copies of this report to congressional committees and
subcommittees with responsibility for transportation safety issues; the
Secretary of Transportation; the Secretary of Energy; the Administrator,
PHMSA; the Assistant Administrator and Chief Safety Officer, PHMSA; the
Deputy Secretary for Natural Gas and Petroleum Technology, Department of
Energy; 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 h  ttp://www.gao.gov.

If you have any questions about this report, please contact me at (202)
512-2834 or s  [email protected]. 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

Impact of Periodic Reassessments on Natural Gas Supply May Be Less than
Foreseen

As the Pipeline Safety Improvement Act of 2002 was being considered, the
Interstate Natural Gas Association of America (INGAA) analyzed the
possible impact of requiring assessments and periodic reassessments and
found that significant disruptions in the natural gas supply and
considerable price increases could occur.1 A more moderate impact was
predicted in three subsequent analyses-(1) two reviews of the INGAA study
performed for the Pipeline and Hazardous Materials Administration (PHMSA)
by the John A. Volpe National Transportation Systems Center and by the
Department of Energy during the congressional debate over the pipeline
bill, and (2) a post-act PHMSA evaluation of its implementing
regulations.2 A waiver provision was included in the 2002 act after
INGAA's study was completed; this may serve as a safety valve if it
appears that the natural gas supply may be disrupted. Finally, our
discussions with 50 natural gas pipeline operators also suggest a more
moderate potential impact than INGAA found.

INGAA Study Expected Significant Supply Disruptions and Price Increases

INGAA's study estimated that periodic assessments under integrity
management could lead to a monthly reduction in natural gas supply of
about 1 to 3 percent, along with price increases to customers, among
others, ranging from $382 million to over $1 billion (in 2002 dollars)
from 2002 through 2010, depending on the frequency of assessments.3 Most
of this price increase would be due to supply disruption and some due to
capital expenditures. INGAA considered the monthly reduction in supply to
be significant because it assumed that gas transmission pipelines would be
removed from service during testing and that some areas of the country
would be more vulnerable to supply disruptions than others.

PHMSA-commissioned Reviews and PHMSA's Regulatory Evaluation Predict More
Moderate Impacts

Both Volpe's and the Department of Energy's 2002 reviews of the INGAA
study concluded that gas transmission pipelines would not be significantly
affected by periodic assessments. The reviews, however, did not attempt to
quantify overall estimates of gas disruptions or price impacts. Rather,
they examined the major assumptions in the INGAA study and discussed
whether the study's results seemed reasonable. PHMSA's final regulatory
evaluation, which was completed in 2004 to assess the impact of PHMSA's
regulations on implementing the 2002 act, concluded that transmission
pipelines' natural gas supply may be somewhat disrupted as a result of
assessments and that cost increases may occur. However, PHMSA acknowledged
that it could not estimate the impact of assessments on gas prices. In
general, the reviews found that the INGAA study's estimates of price
impacts represent a worst-case scenario because of several overly
pessimistic assumptions. For example, the INGAA study

o underestimated the ability of the pipeline network to mitigate 
disruptions. INGAA assumed that pipeline assessments would generally
reduce pipeline capacity temporarily, thereby disrupting the supply and
increasing the price of natural gas. Yet, both Volpe's and the Department
of Energy's reviews found that the INGAA study did not sufficiently
account for redundancies in the nation's natural gas transmission pipeline
network. Redundancies enable operators to mitigate potential disruptions
during assessments by rerouting gas through the network.

Operators we contacted that have higher-stress gas transmission pipelines4
generally indicated that their pipeline infrastructure is versatile and
includes such redundancies as parallel pipelines or looping capabilities
that allow gas to flow to customers while portions of the pipeline are
assessed or repaired.5 (See fig. 7.) Operators of lower-stress pipelines6
reported that they typically use a set of laterals,7 which feed an
interconnected gas distribution system and allow them to plan around
disruptions. In addition, lower-stress operators can use liquid or
compressed natural gas that is located at their facilities or transported
by trucks to specified locations. Forty-four of the 50 natural gas
operators (88 percent) that we contacted have some type of alternative gas
supply, such as storage facilities and other gas suppliers, to meet
customers' short-term needs.

Figure 7: Parallel Natural Gas Transmission Pipelines Can Help Maintain
Product Supply

o assumed that a large amount of transmission mileage would require
assessments because of over-testing. The INGAA study concluded that the
number of gas transmission pipeline miles within highly populated or
frequently used areas is only about 5 percent of the total mileage in the
U.S. Nonetheless, the study assumed that over 80 percent of mainline
interstate pipeline miles would require assessing, because the pipeline
miles that are located within the highly populated areas are scattered
throughout the pipeline system, and inspection methods like in-line
testing can only be inserted and retrieved in certain locations that may
lie outside highly populated or frequently used locations. As a result,
the study assumed that operators of these pipelines would assess over
1,500 percent more miles than are within the highly populated areas. On
the basis of comments from industry groups, PHMSA's regulatory evaluation
assumed that operators would assess about 625 percent more miles when
using in-line inspection testing and about 25 percent more miles when
using hydrostatic testing, but no over-testing when using the direct
assessment method. Baseline assessment results to date seem to support the
lower over-testing estimate: as of December 31, 2005, on the basis of
performance reports submitted to PHMSA, operators assessed about 650
percent more miles overall than are located in highly populated or
frequently used areas.8

o assumed that only hydrostatic testing would be used on delivery
laterals. The INGAA study predicted that operators would use only
hydrostatic testing on lateral gas transmission pipelines because it
assumed that very few laterals can accommodate in-line testing. Under
hydrostatic testing, water pressure is used to test the condition of
pipelines; therefore, all of the capacity of a pipeline segment must be
removed for a period of time.

Volpe's review concluded that this particular assumption represents the
worst possible impact of assessments on lateral pipelines because it does
not allow for the use of in-line testing or direct assessment. Based on
discussions with operators and public comments on PHMSA's draft regulatory
analysis, the PHMSA regulatory evaluation also assumed that few operators
would use hydrostatic testing. INGAA's study also did not address the
development of new technologies that could allow in-line inspection of
smaller diameter pipelines. As discussed earlier, new technology is being
developed. Finally, operators we contacted reported that they do not plan
to use hydrostatic testing extensively. As discussed earlier, only about 4
percent of the mileage will be reassessed using hydrostatic testing. This
testing will typically be over relatively small lengths of pipeline (from
0.8 to 331 miles).

o did not incorporate the ability of operators to obtain waivers. The
INGAA study did not consider the possible impact of a waiver provision in
the 2002 act on maintaining the natural gas supply. This was
understandable because the waiver provision was added to the bills under
consideration after the INGAA study was completed. The act allows the
PHMSA to waive or modify any requirement for operators to conduct
reassessments when they need to maintain product supply as long as it is
consistent with pipeline safety.9 Twenty-one of the 50 natural gas
operators (42 percent) that we contacted said that they would consider
applying for a waiver, if needed, and 23 (46 percent) told us that they
did not plan to apply for a waiver. Three of the operators were uncertain,
and the remaining three operators did not provide us with a response.
Fourteen of the 26 operators that either did not plan to apply for a
waiver or were unsure about doing so said that it is too early to
determine the need for applying for waivers. They obtained the necessary
equipment to conduct assessments or developed plans for handling potential
natural gas supply disruptions.10

Operators Contacted Found Assessments Have Had Minimal Impact on Supply

Pipeline operators we contacted told us that assessments and repairs of
even their riskiest gas transmission pipelines have not significantly
disrupted the natural gas supplied to customers, such as local
distribution companies and power plants. These 50 natural gas transmission
operators and local distribution companies had assessed about 4,100 miles
of pipeline in highly populated or frequently used areas, as of December
2005 (latest data available)-or about 21 percent of the total gas
transmission mileage in these areas in the nation and about 62 percent of
the pipeline mileage located in frequently used or highly populated areas
assessed to date. Of the 44 operators that have begun baseline
assessments, 26 (59 percent) indicated that their assessments and repairs
did not require them to shut down their pipelines or reduce their
operating pressure. Sixteen operators (36 percent) reported minor
disruptions in their gas supply because they temporarily shut down
pipelines and reduced operating pressure to conduct assessments or
repairs. These operators told us that they used alternative gas sources,
such as liquefied natural gas, to sustain their customers' gas supply. The
remaining two operators (5 percent) were located in regions that have
limited excess gas capacity. Both operators reported that they could not
meet all of the natural gas needs of their customers when their pipelines
were shut down to perform assessments or repairs. Some customers,
especially those with interruptible contracts,11 did not receive gas from
the pipelines for several days, but they were able to obtain gas from
alternative sources.

Eleven of the 44 operators were located in regions that have limited
excess gas capacity-the Northeast, the Rocky Mountains, and the
Southwest-and reported minor supply disruptions. Five of the 11
operators-all of which operate lower-stress gas transmission
pipelines-reported that none of these disruptions in natural gas supply
were caused by assessments or repairs. Four operators reported instances
in which immediate repairs caused a reduction in operating pressure;
however, they maintained natural gas supply by relying on alternative gas
sources.12 Since PHMSA does not require that operators report to it the
nature of the problems, we do not know how many immediate repairs, if any,
were due to corrosion. And, as previously mentioned, 2 of the 11 operators
reported natural gas supply disruptions; although they had to shut down
their pipelines due to assessments or repairs, customers were able to
obtain natural gas from other sources.

In early 2006, INGAA and AGA polled their members about their experiences
with and plans for conducting assessments and reassessments during
off-peak and peak months.13 Overall, INGAA and AGA found that, from 2003
to 2012, members plan to conduct 76 percent of their baseline assessments
and reassessments on their gas transmission pipelines (as measured in
miles) during the off-peak spring and summer months, 18 percent in the
fall, and 6 percent in the winter. According to an INGAA official, most of
the assessment activity that results in temporary reductions in gas supply
due to repairs being made will likely affect markets regionally. If
assessments occur when pipelines are constrained for capacity, an increase
in delivered gas prices will occur. Overall, assessments will only affect
small groups of the nation's population, but they will have a consumer
price impact in those affected areas.

Our findings from these operators, while not necessarily representative of
all operators, are encouraging. First, these findings do represent a
sizeable proportion (61 percent) of the mileage assessed to date. Second,
the segments that operators assessed were supposed to be the riskiest
segments (those most susceptible to ruptures or leaks) of the gas
transmission pipelines located in highly populated or frequently used
areas. If so, there should be fewer repairs needed for subsequent baseline
assessments of less risky segments, and hence fewer disruptions in supply.

Post-act Industry Polling Found Members Plan to Modify and Repair
Pipelines, Which May Affect Natural Gas Supply

The 2006 INGAA and AGA polling of their members did not explicitly ask for
the extent to which their members experienced supply disruptions because
of baseline assessments or repairs. However, INGAA and AGA did ask members
to identify the amount of pipeline modifications and repairs that would be
necessary for conducting baseline assessments and reassessments,
activities that could disrupt supply. Overall, INGAA and AGA found that
about 50,000 of the 180,000 miles of gas transmission pipelines that were
reported by responding operators are scheduled for or have already
undergone (1) modifications to allow in-line inspection tools to access
pipeline segments (2) repairs to eliminate major defects or (3) monitoring
for minor problems.14 According to a senior INGAA official, assessments
and pipeline modifications can generally follow a prearranged schedule;
however, pipeline repairs are unpredictable. Repairs often require
pipelines to be shut down, which could have an effect on natural gas
supply.15 However, PHMSA officials report that only the worst pipeline
problems require pipelines to be shutdown for repair. From 2003 to 2012,
38,000 of the 50,000 pipeline miles (76 percent) have been scheduled for

modifications or repairs during the off-peak spring and summer months to
mitigate supply disruptions.16

Department of Energy Expects Little Disruption in the Natural Gas Supply

Officials from the Office of Oil and Gas within the Department of Energy
told us that the integrity management program, including the 7-year
reassessment requirement, is not likely to significantly disrupt the
natural gas supply. They told us that operators have, among other things,
sufficient system redundancies, such as parallel lines, to maintain
product supply. The Department of Energy has completed several regional
analyses of the possible effects of the disruptions in the natural gas
supply caused by such events as extreme weather conditions (e.g., extended
cold periods and hurricanes). It is completing other analyses as well.
However, because these are being done at the regional level, their results
are too broad to help inform us about more localized and subregional
potential disruptions.

Appendix II

Scope and Methodology

To understand how the findings from operators' baseline assessments inform
us about the need to reassess gas transmission pipelines at least every 7
years, we reviewed the requirements of the Pipeline Safety Improvement Act
of 2002 and PHMSA's implementing regulations. We also reviewed information
about setting reassessment intervals for gas transmission pipelines,
including industry consensus standards for maximum reassessment intervals
developed by the American Society of Mechanical Engineers, and documents
obtained from PHMSA, industry, and other stakeholders. We discussed this
issue with officials from PHMSA, other federal agencies, industry
associations, companies that perform research in this area, state safety
representatives, and safety advocacy groups. (These organizations are
listed at the end of this appendix.)

We also analyzed data from PHMSA on the number of immediate repairs
reported by operators as a result of baseline assessments conducted
through December 2005 (latest data available) and the number of natural
gas pipeline incidents reported to PHMSA.

We contacted 52 pipeline operators (50 natural gas and 2 hydrogen
operators) from among the 447 operators that reported that they operate
gas transmission pipelines in highly populated or frequently used areas.
Forty-four of these operators have begun baseline assessments. We selected
those operators for which the baseline assessments and reassessments could
be expected to have the greatest impact, all else being equal: larger and
smaller transmission pipelines and local distribution companies with the
highest proportion of pipeline miles in highly populated or frequently
used areas to total system miles. We also selected operators located in
three regions of the country that several studies and our stakeholders
consider to be vulnerable to energy supply disruptions: the Northeast, the
Southwest, and the Rocky Mountains.

The 52 operators reported that they have assessed about 4,100 of the 6,700
miles (61 percent) of pipeline segments, as of December 2005. Overall,
these operators have assessed about 21 percent of the 20,000 miles of
pipeline that operators have reported as being within highly populated or
frequently used areas. Because we used a nonprobability method of

selecting these operators, we cannot project our findings nationwide.1
Contacting a larger number of operators or selecting them through a
statistical sample would not have been feasible due to resource and time
constraints. Nonetheless, these 52 operators do represent a substantial
portion of the miles assessed to date and of the total number of reported
miles of pipeline in highly populated or frequently used areas.

For these 52 operators, we conducted semistructured interviews to collect
qualitative and quantitative information on the degree to which they found
anomalies during the baseline assessments and, based on these results, the
frequency with which they would reassess these pipeline segments under
American Society for Mechanical Engineers standards for managing the
system integrity of gas pipelines (ASME B31.8S-2004) if the 7-year
reassessment requirement were not in place. As part of our work, we asked
operators to identify the steps that they take to ensure the quality of
their baseline assessments and reassessments, such as ensuring that
competent persons are involved in determining reassessment intervals and
conducting periodic internal or third-party reviews of their integrity
management programs, as recommended by PHMSA regulations and industry
standards. We relied on the operators' professional judgment in reporting
on the conditions they found during their assessments.

To determine the extent to which gas transmission pipeline operators and
local distribution companies will likely have the resources to reassess
their pipelines, at least every 7 years, we synthesized testimonial and
documentary evidence obtained from our discussions with (1) 52 operators
(as described above) and (2) pipeline assessment tool contractors, direct
assessment vendors, and industry associations on the prospective
availability of equipment, equipment operators, and data analysts to
interpret results. We synthesized the information from the 52 operators to
determine the aggregate level of actual and planned assessments and
reassessments through 2012. We compared our findings with the results from
an INGAA/AGA data collection effort, conducted in 2006, on the same topic.
We then discussed our results with INGAA and analyzed the data obtained
from both efforts to try to understand any differences in results.

To assess the reliability of information provided to us from PHMSA, INGAA,
and AGA, we performed a number of analyses. For the information provided
to us from PHMSA, we compared the number of immediate repairs operators
reported to us to the number of immediate repairs they reported to PHMSA.
To assess the reliability of the data provided to us from INGAA and AGA,
we also compared the reported responses of operators that were included in
INGAA/AGA's and our efforts. In addition, we checked the accuracy of
INGAA/AGA's calculations. We determined that the data were sufficiently
reliable for the types of analyses we present in this report.

Other Aspects of Our Work

To determine the potential impact of the 7-year reassessment requirement
on the nation's natural gas supply, we contacted officials from PHMSA, the
Department of Energy, industry associations, and research firms to discuss
how the potential shutdown of gas transmission pipelines or operation
under reduced pressure-as a result of baseline assessments, reassessments,
and repairs-might affect the continued supply of natural gas. We also
obtained information from the Department of Energy on the results of
analyses of the overall vulnerability of natural gas supplies in several
regions of the nation to extreme conditions, such as extreme cold weather.

Further, we asked the 50 natural gas operators that we contacted about the
vulnerability of their pipelines to supply disruption and the potential
impact on customers. This included 11 operators located in the three
regions of the country that have limited excess supply gas capacity. We
also discussed how their baseline assessments and any resulting repairs
have affected their customers to date. Finally, we compared operators'
experiences in performing assessments, reassessments, and repairs to the
assumptions made in the 2002 INGAA study of the potential effects of the
proposed integrity management program, two reviews of this study, and
PHMSA's final regulatory evaluation. The reviews were performed by the
John A. Volpe National Transportation Systems Center and the Department of
Energy at the request of PHMSA.2

Organizations Contacted

In addition to the 52 pipeline operators and four inspection contractors
that we contacted, we met with or contacted the following organizations:

Department of Transportation

Office of Inspector General Pipeline and Hazardous Materials Safety
Administration

Other Federal Agencies

Department of Energy Federal Energy Regulatory Commission National
Institute of Standards and Technology National Transportation Safety Board

Industry Associations

American Gas Association American Public Gas Association Inline Inspection
Association Interstate Natural Gas Association of America Midwest Energy
Association Northeast Gas Association

State Regulatory Associations

National Association of Pipeline Safety Representatives National
Association of Regulatory Utility Commissioners New Jersey Public Utility
Commission

Research Firms

Energy and Environmental Analysis, Inc. Battelle Gas Technology Institute
John A. Volpe National Transportation Systems Center Pipeline Research
Council International

Technical Experts

American Society of Mechanical Engineers American Society for Testing and
Materials Kiefner and Associates, Inc. National Association of Corrosion
Engineers

Pipeline Safety Advocacy Groups

Common Ground Alliance Cook Inlet Keeper Pipeline Safety Trust

Appendix III

Contact and Staff Acknowledgments

GAO Contact

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

Staff Acknowledgments

In addition to the above, James Ratzenberger, Assistant Director; Timothy
Bober; Anne Dilger; Seth Dykes; Timothy Guinane; Brandon Haller; Bert
Japikse; and Matthew LaTour made key contributions to this report.

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www.gao.gov/cgi-bin/getrpt? GAO-06-945 .

To view the full product, including the scope
and methodology, click on the link above.

For more information, contact Katherine Siggerud (202) 512-2834 or
[email protected].

Highlights of GAO-06-945 , a report to congressional committees

September 2006

NATURAL GAS PIPELINE SAFETY

Risk-Based Standards Should Allow Operators to Better Tailor Reassessments
to Pipeline Threats

The Pipeline Safety Improvement Act of 2002 requires that operators (1)
assess gas transmission pipeline segments in about 20,000 miles of highly
populated or frequently used areas by 2012 for safety threats, such as
incorrect operation and corrosion (called baseline assessments), (2)
remedy defects, and (3) reassess these segments at least every 7 years.
Under the Pipeline and Hazardous Materials Safety Administration's (PHMSA)
regulations, operators must reassess their pipeline segments for corrosion
at least every 7 years and for all safety threats at least every 10, 15,
or 20 years, based on industry consensus standards-and more frequently if
conditions warrant. Operators must also carry out other prevention and
mitigation measures.

To meet a requirement in the 2002 act, this study addresses how the
results of baseline assessments and other information inform us on the
need to reassess gas transmission pipelines every 7 years and whether
inspection services and tools are likely to be available to do so, among
other things. In conducting its work, GAO contacted 52 operators that have
carried out about two-thirds of the baseline assessments conducted to
date.

What GAO Recommends

The Congress should consider allowing gas transmission pipeline operators
to reassess their pipelines using risk-based standards. In commenting on a
draft of this report, the Department of Transportation generally agreed
with it and the Department of Energy stated that it had no comments.

Periodic reassessments of gas transmission pipelines are useful because
safety threats can change. However, the 7-year requirement appears to be
conservative because (1) most operators found few major problems during
baseline assessments, and (2) serious pipeline incidents involving
corrosion are rare, among other reasons. Through December 2005 (latest
data available), 76 percent of the operators (182 of 241) that had begun
baseline assessments reported to PHMSA that their pipelines required only
minor repairs. These results are encouraging because operators are
required to assess their riskiest segments first. Since operators are also
required to repair these problems, the overall safety and condition of
their pipelines should be enhanced before reassessments begin. In
addition, PHMSA data suggest that serious gas transmission pipeline
problems due to corrosion are rare. For example, there have been no deaths
or injuries as a result of incidents due to corrosion since 2001. Of the
52 operators contacted that have calculated reassessment intervals, the
large majority (20 of 23) told GAO that based on conditions identified
during baseline assessments, they could safely reassess their pipelines
for corrosion, every 10, 15, or 20 years-as industry consensus standards
prescribe unless pipeline conditions warrant an earlier assessment.

Sufficient resources may be available for operators' reassessment
activities, but some uncertainty exists. For the most part, the 52
operators that GAO contacted expect to be able to obtain the services and
tools needed through 2012. However, they expressed some concern about
whether enough qualified vendors for the confirmatory and direct
assessment methods (above-ground inspections followed by excavations)
would be available. Industry associations and GAO attempted to determine
the degree to which activity would increase from 2010 to 2012, when
operators begin reassessing pipelines while completing baseline
assessments. An industry effort showed an increase in assessment and
reassessment activity, but GAO's showed a decrease. The reasons for the
differences are not clear but may be due, in part, to differences in the
operators contacted and the methodologies used in collecting this
information.

Framework for Assessing and Reassessing Pipelines for Safety Threats
*** End of document. ***