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Testimony: 

Before the Subcommittee on Highways, Transit and Pipelines, Committee 
on Transportation and Infrastructure, House of Representatives: 

United States Government Accountability Office: 

GAO: 

For Release on Delivery Expected at 10:00 a.m. EST: 

Thursday, March 16, 2006: 

Gas Pipeline Safety: 

Preliminary Observations on the Integrity Management Program and 7-Year 
Reassessment Requirement: 

Statement of Katherine Siggerud, Director: 
Physical Infrastructure Issues: 

GAO-06-474T: 

GAO Highlights: 

Highlights of GAO-06-474T, a testimony before the Subcommittee on 
Highways, Transit and Pipelines, Committee on Transportation and 
Infrastructure, House of Representatives: 

Why GAO Did This Study: 

About a dozen people are killed or injured in natural gas transmission 
pipeline incidents each year. In an effort to improve upon this safety 
record, the Pipeline Safety Improvement Act of 2002 requires that 
operators assess pipeline segments in about 20,000 miles of highly 
populated or frequented areas for safety risks, such as corrosion, 
welding defects, or incorrect operation. Half of these baseline 
assessments must be done by December 2007, and the remainder by 
December 2012. Operators must then repair or replace any defective 
pipelines, and reassess these pipeline segments for corrosion damage at 
least every 7 years. The Pipeline and Hazardous Materials Safety 
Administration (PHMSA) administers this program, called gas integrity 
management. 

This testimony is based on ongoing work for this Subcommittee and for 
other committees, as required by the 2002 act. The testimony provides 
preliminary results on the safety effects of (1) PHMSA’s gas integrity 
management program and (2) the requirement that operators reassess 
their natural gas pipelines at least every 7 years. It also discusses 
how PHMSA has acted to strengthen its enforcement program in response 
to recommendations GAO made in 2004. 

GAO expects to issue two reports this fall that will address these and 
other topics. 

What GAO Found: 

Early indications suggest that the gas transmission pipeline integrity 
management program enhances public safety by supplementing existing 
safety standards with risk-based management principles. Operators have 
reported that they have assessed about 6,700 miles as of December 2005 
and completed 338 repairs for problems they are required to address 
immediately. Operators told GAO that the primary benefit of the program 
is the comprehensive knowledge they must acquire about the condition of 
their pipelines. For some operators, the integrity management program 
has prompted such assessments for the first time. Operators raised 
concerns about (1) their uncertainty over the level of documentation 
that PHMSA requires and (2) whether their pipelines need to be 
reassessed at least every 7 years. 

The 7-year reassessment requirement is generally consistent with the 
industry consensus standard of at least every 5 to 10 years for 
reassessing pipelines operating under higher stress (higher operating 
pressure in relation to wall strength). The majority of transmission 
pipelines in the U.S. are estimated to be higher stress pipelines. 
However, most operators told GAO that the 7-year requirement is 
conservative for pipelines that operate under lower stress because they 
found few problems requiring reassessments earlier than the 15 to 20 
years under the industry standard. Operators GAO contacted said that 
periodic reassessments are beneficial for finding and preventing 
problems; but they favored reassessments on severity of risk rather 
than a one-size-fits-all standard. Operators did not expect that the 
existence of an “overlap period” from 2010 through 2012, when operators 
will be conducting baseline assessments and reassessments at the same 
time, would create problems in finding resources to conduct 
reassessments. 

PHMSA has developed a reasonable enforcement strategy framework that is 
responsive to GAO’s earlier recommendations. PHMSA’s strategy is aimed 
at reducing pipeline incidents and damage through direct enforcement 
and through prevention involving the pipeline industry and stakeholders 
(such as state regulators). Among other things, the strategy entails 
(1) using risk-based enforcement and dealing severely with significant 
noncompliance and repeat offenses, (2) increasing knowledge and 
accountability for results by clearly communicating expectations for 
operators’ compliance, (3) developing comprehensive guidance tools and 
training inspectors on their use, and (4) effectively using state 
inspection capabilities. 

Pipeline Failure Resulting from Corrosion: 

[See PDF for image] 

[End of figure] 

www.gao.gov/cgi-bin/getrpt?GAO-06-474T. 

To view the full product, including the scope and methodology, click on 
the link above. For more information, contact Katherine Siggerud at 
(202) 512-2834 or siggerudk@gao.gov. 

[End of section] 

Mr. Chairman and Members of the Subcommittee: 

We appreciate the opportunity to participate in this oversight hearing 
on the Pipeline Safety Improvement Act of 2002. The act strengthens 
federal pipeline safety programs and enforcement, state oversight of 
pipeline operators, and public education on pipeline safety. The 
information that we and others will provide today should help the 
Congress as it prepares to reauthorize pipeline safety programs. 

My statement is based on the preliminary results of our ongoing work 
for this Subcommittee and others. As directed by the 2002 act, we are 
assessing the effects on safety stemming from (1) the Pipeline and 
Hazardous Materials Safety Administration's (PHMSA) integrity 
management program for gas transmission pipelines and (2) the 
requirement that pipeline operators reassess their natural gas 
pipelines for certain safety risks at least every 7 years.[Footnote 1] 
In addition, I would also like to briefly touch on how PHMSA has acted 
to strengthen its enforcement program. I testified on PHMSA's 
enforcement program before this Subcommittee almost 2 years 
ago,[Footnote 2] and believe that this is a good opportunity to update 
you on some positive accomplishments. 

Our work is based on our review of laws, regulations, and other PHMSA 
guidance, as well as discussions with a broad range of stakeholders, 
including industry trade associations, pipeline safety advocate groups, 
state pipeline regulators, and consensus standards 
organizations.[Footnote 3] In addition, we contacted 25 pipeline 
operators about the matters that I will discuss today. We chose 
operators for which integrity management could have the greatest 
impact, all else being equal: larger and smaller operators with the 
highest proportion of pipelines in highly populated or frequented areas 
to total miles of pipeline. These operators represent about half of the 
miles of pipeline assessed to date.[Footnote 4] We relied on pipeline 
operators' professional judgment in reporting on the conditions that 
they found during their assessments of safety risks. As part of our 
work, we assessed the internal controls and the reliability of the data 
elements needed for this engagement, and we determined that the data 
elements were sufficiently reliable for our purposes. We performed our 
work in accordance with generally accepted government auditing 
standards from August 2005 to March 2006. 

In summary: 

* Implementation of integrity management is in its early stages as 
PHMSA's regulations were finalized in 2004. Early indications suggest 
that the gas integrity management program has enhanced public safety by 
requiring that operators identify and address the risks to pipeline 
segments located in areas that are most likely to affect public safety. 
Operators believe that the primary benefit of the program is the 
comprehensive knowledge they must acquire about the condition of their 
pipelines. However, operators have raised concerns about (1) their 
uncertainty over the level of documentation required by the program and 
(2) whether the requirement to reassess their pipelines at least every 
7 years contributes to increased safety. PHMSA's initial inspections of 
11 operators' integrity management programs have shown that operators 
are doing well in assessing their pipelines and making repairs but that 
they need to better document their management practices and decisions. 

* Overall, pipeline operators have reported to PHMSA that, in the 
almost 6,700 miles of pipeline they have assessed, they have found 338 
problems that required immediate repair or replacement[Footnote 5]-- 
about 1 problem every 20 miles, on average. The 25 operators that we 
contacted--which represent about half of the 6,700 miles assessed so 
far--told us that, if the 7-year requirement were not in place, they 
would reassess the pipeline segments located in highly populated or 
frequented areas every 10, 15, or 20 years following industry consensus 
standards. The 7-year reassessment requirement is similar to industry 
standards for pipelines operating under higher-stress (higher operating 
pressure in relation to wall strength) where the industry standard for 
reassessments is no more than 5 to 10 years, depending on operating 
pressure. However, operators told us that the 7-year reassessment 
requirement is conservative for pipelines operating under lower-stress, 
where the industry reassessment standard can extend to 15 to 20 years. 
The large majority of transmission pipelines in the U.S. are estimated 
to be higher-stress pipelines, based on information from industry 
associations. Most operators of lower-stress pipelines told us that 
they found few problems during baseline assessments that would require 
reassessments before 15 or 20 years. Operators that we contacted 
believed that periodic reassessments of their pipelines will be 
beneficial in finding and preventing problems. However, they favored 
conducting reassessments based on severity of risk rather than applying 
a one-size-fits-all standard. Operators did not expect that the 
existence of an "overlap period" from 2010 through 2012, when operators 
will be completing baseline assessments and beginning reassessments at 
the same time, would create problems in finding resources to conduct 
reassessments.[Footnote 6] The existence of an overlap was an industry 
concern while the 2002 act was being debated. 

* PHMSA has developed a reasonable enforcement strategy framework that 
is responsive to the recommendations that we made in 2004. PHMSA's 
strategy is aimed at reducing pipeline incidents and damage through 
both direct enforcement and prevention. The strategy entails, among 
other things, (1) using risk-based enforcement that clearly reflects 
potential risk and seriousness and dealing severely with operators' 
significant noncompliance and repeat offenses; (2) increasing knowledge 
and accountability for results by clearly communicating expectations 
for operator compliance; (3) developing comprehensive guidance tools, 
along with training inspectors on their use; and (4) effectively using 
state inspection capabilities: 

Background: 

On average, about 3 people have died and about 8 people have been 
injured each year over the last 10 years in natural gas transmission 
pipeline incidents. The number of incidents has increased from 77 in 
1996 to 122 and 200 in 2004 and 2005, respectively, mostly reflecting 
more frequent occurrence of property damage.[Footnote 7] Much of this 
increase may be attributed to increases in the price of gas (which has 
the effect of lowering the reporting threshold) over the past several 
years and to damage as a result of hurricanes in 2005. 

As a means of enhancing the security and safety of gas pipelines, the 
2002 act included an integrity management structure that, in part, 
requires that operators of gas transmission pipelines systematically 
assess for safety risks the portions of their pipelines located in 
highly populated or frequently used areas, such as parks. Safety risks 
include corrosion, welding defects and failures, third-party damage 
(e.g., from excavation equipment), land movement, and incorrect 
operation. The act requires that operators perform these assessments 
(called baseline assessments) on half of the pipeline mileage in highly 
populated or frequented areas by December 2007 and the remainder by 
December 2012. Those pipeline segments potentially facing the greatest 
risks are to be assessed first. Operators must then repair or replace 
defective pipelines. Risk-based assessments are seen by many as having 
a greater potential to improve safety than focusing on compliance with 
safety standards regardless of the threat to pipeline safety. 

The act further provides that pipeline segments in highly populated or 
frequented areas must be reassessed for safety risks at least every 7 
years. PHMSA's regulations implemented the act by requiring that 
operators reassess their pipelines for corrosion damage every 7 years, 
using an assessment technique called confirmatory direct 
assessment.[Footnote 8] Under these regulations, and consistent with 
industry national consensus standards, operators must also reassess 
their pipeline segments for any safety risk at least every 5, 10, 15, 
or 20 years, depending on the pressure under which the pipeline 
segments are operated and the condition of the pipeline. 

There are about 900 operators of about 300,000 miles of gas 
transmission and gathering pipelines in the United States. As of 
December 2005, according to PHMSA, 429 of these operators reported that 
about 20,000 miles of their pipelines lie in highly populated or 
frequented areas (about 7 percent of all transmission pipeline miles). 
Operators reported that they had as many as about 1,600 miles and as 
few as 0.02 miles of pipeline in these areas. 

PHMSA, within the Department of Transportation, administers the 
national regulatory program to ensure the safe transportation of gas 
and hazardous liquids (e.g., oil, gasoline, and anhydrous ammonia) by 
pipeline. The agency attempts to ensure the safe operation of pipelines 
through regulation, national consensus standards, research, education 
(e.g., to prevent excavation-related damage), oversight of the industry 
through inspections, and enforcement when safety problems are found. 
PHMSA employs about 165 staff in its pipeline safety program, about 
half of whom are pipeline inspectors who inspect gas and hazardous 
liquid pipelines under integrity management and other more traditional 
compliance programs. Nine PHMSA inspectors are currently devoted to the 
gas integrity management program. In addition, PHMSA is assisted by 
inspectors in 48 states, the District of Columbia, and Puerto Rico. 

Early Indications Suggest that Gas Integrity Management Enhances Public 
Safety, but Operators Raise Some Concerns About Implementation: 

While the gas integrity management program is still being implemented, 
early indications suggest that it enhances public safety by 
supplementing existing safety standards with risk-based management 
principles. Prior to the integrity management program, there were, and 
still are, minimum safety standards that operators must meet for the 
design, construction, testing, inspection, operation, and maintenance 
of gas transmission pipelines. These standards apply equally to all 
pipelines and provide the public with a basic level of protection from 
pipeline failures. However, minimum standards do not require operators 
to identify and address risks that are specific to their pipelines nor 
do they require operators to assess the integrity of their pipelines. 
While some operators did assess the integrity of some of their 
pipelines, others did not. Some pipelines have been in operation for 40 
or more years with no assessment. The gas integrity management 
requirements, finalized in 2004, go beyond the existing safety 
standards by requiring operators, regardless of size, to routinely 
assess pipelines in highly populated or frequented areas for specific 
threats, take action to mitigate the threats, and document management 
practices and decision-making processes. 

Representatives from the pipeline industry, safety advocate groups, and 
operators we have contacted agree that the integrity management program 
enhances public safety. Some operators noted that, although the 
program's requirements can be costly and time consuming to implement, 
the benefits to date are worth the cost. The primary benefit identified 
was the comprehensive knowledge the program requires all operators to 
have of their pipeline systems. For example, under integrity 
management, operators must gather and analyze information about their 
pipelines in highly populated or frequented areas to get a complete 
picture of the condition of those lines. This includes developing maps 
of the pipeline system and information on corrosion protection, exposed 
pipeline, threats from excavation or other third-party damage, and the 
installation of automatic shut off valves. Another benefit cited was 
improved communications within the company. Investigations of pipeline 
incidents have shown that, in some cases, an operator possessed 
information that could have prevented an incident but had not been 
shared with employees who needed it most. Integrity management requires 
operators to pull together pipeline data from various sources within 
the company to identify threats to the pipelines, leading to more 
interaction among different departments within pipeline companies. 
Finally, integrity management focuses operator resources in those areas 
where an incident could have the greatest impact. 

While industry and operator representatives have provided examples of 
the early benefits of integrity management, operators must report semi- 
annually on performance measures that should quantitatively demonstrate 
the impact of the program over time. These measures include the total 
mileage of pipelines and the mileage of pipelines assessed in highly 
populated or frequented areas, as well as the number of repairs made 
and leaks, failures, and incidents identified in these areas. In the 2 
years that operators have reported the results of integrity management, 
they have assessed about 6,700 miles of their 20,000 miles of pipelines 
located in highly populated or frequented areas and they have completed 
338 repairs that were immediately required and another 998 repairs that 
were less urgent. While it is not possible to determine how many of 
these needed repairs would have been identified without integrity 
management, it is clear that the requirement to routinely assess 
pipelines enables operators to identify problems that may otherwise go 
undetected. For example, one operator told us that it had complied with 
all the minimum safety standards on its pipeline, and the pipeline 
appeared to be in good condition. The operator then assessed the 
condition of a segment of the pipeline under its integrity management 
program and found a serious problem causing it to shut the line down 
for immediate repair. 

One of the most frequently cited concerns by the 25 operators we 
contacted was the uncertainty about the level of documentation needed 
to support their gas integrity management programs. PHMSA requires 
operators to develop an integrity management program and provides a 
broad framework for the elements that should be included in the 
program. Each operator must develop and document specific policies and 
procedures to demonstrate their commitment to compliance and 
implementation of the integrity management requirements. In addition, 
an operator must document any decisions made related to integrity 
management. For example, an operator must document how it identified 
the threats to its pipeline in highly populated or frequented areas and 
who was involved in identifying the threats, their qualifications, and 
the data they used. While the operators we contacted did not disagree 
with the need to document their policies and procedures, some said that 
the detailed documentation required for every decision is very time 
consuming and does not contribute to the safety of pipeline operations. 
Moreover, they are concerned that they will not know if they have 
enough documentation until their program has been inspected. After 
conducting 11 inspections, PHMSA found that, while operators are doing 
well in conducting assessments and making the identified repairs, they 
are having difficulty overall in the development and documentation of 
their management processes. Another concern raised by most of the 
operators is the requirement to reassess their pipelines at least every 
7 years. I will discuss the 7-year reassessment requirement in more 
detail shortly. 

As part of our assessment of the integrity management program, we are 
also examining how PHMSA and state pipeline agencies plan to oversee 
operator implementation of the program. To help federal and state 
inspectors prepare for and conduct integrity management inspections, 
PHMSA developed detailed inspection protocols tied to the integrity 
management regulations and a series of training courses covering the 
protocols and other relevant topics, such as corrosion and in-line 
inspection.[Footnote 9] Furthermore, in response to our 2002 
recommendation,[Footnote 10] PHMSA has been working to improve its 
communication with states about their role in overseeing integrity 
management programs. For example, PHMSA's efforts include (1) inviting 
state inspectors to attend federal inspections, (2) creating a website 
containing inspection information, and (3) providing a series of 
updates through the National Association of Pipeline Safety 
Representatives. I am pleased to report that preliminary results from 
an ongoing survey of state pipeline agencies (with more than half the 
states responding thus far) show that the majority of states that 
reported believe that the communication from PHMSA has been very or 
extremely useful in helping them understand their role and 
responsibilities in conducting integrity management 
inspections.[Footnote 11] 

7-Year Reassessment Requirement May be Appropriate for Some Operators 
but Conservative for Others: 

Nationwide, pipeline operators reported to PHMSA that they have found, 
on average, about one problem requiring immediate repair or replacement 
for every 20 miles of pipeline assessed in highly populated or 
frequented areas. Operators we contacted recognize the benefits of 
reassessments; however, almost all would prefer following the industry 
national consensus standards that use safety risk, rather than a 
prescribed term, for determining when to reassess their pipelines. Most 
operators expect to be able to acquire the services and tools needed to 
conduct these reassessments including during an overlap period when 
they are starting to reassess pipeline segments while completing 
baseline assessments. 

Operators Favor a Risk-based, Rather than a One-Size-Fits-All 
Reassessment Standard: 

As discussed earlier, as of December 2005, operators nationwide have 
notified PHMSA of 338 problems that required immediate repair in the 
6,700 miles they have assessed--about one immediate repair required for 
every 20 miles of pipeline assessed in highly populated or frequented 
areas. 

The number of immediate repairs may be due, in part, to some operators 
systematically assessing their pipelines for the first time as a result 
of the 2002 act. Of the 25 transmission operators and local 
distribution companies that we contacted, most told us that they found 
few safety problems that required reducing pressure and performing 
immediate repairs during baseline assessments covering (1) about 3,000 
miles of pipeline in highly populated or frequented areas and about (2) 
35,000 miles outside of these areas.[Footnote 12] (See fig. 1.) Most 
operators reported finding pipelines in good condition and free of 
major defects, requiring only minor repairs or recoating. A few 
operators found more than 10 immediate repairs. Operators nonetheless 
found these assessments valuable in determining the condition of their 
pipelines and finding damage. 

Figure 1: Number of Immediate Repairs Needed as Found During Baseline 
Assessments: 

[See PDF for image] 

Note: To prevent distortion, we excluded 3 of the 25 operators we 
contacted because they had assessed 0 miles of pipeline to date. This 
figure includes the immediate repairs for pipeline located both inside 
and outside of highly populated or frequented areas. 

[End of figure] 

Most of the operators told us that, if the 7-year reassessment 
requirement was not in place, they would respond to the conditions that 
they identified during baseline assessments by reassessing their 
pipelines every 10, 15, or 20 years, based on industry consensus 
standards. These baseline assessment findings suggest that--at least 
for the operators we contacted--the 7-year requirement is conservative. 
However, the 7-year reassessment requirement may be more appropriate 
for higher-stress pipelines than for lower-stress pipelines. 

The 7-year reassessment requirement is generally more consistent with 
scientific-and engineering-based intervals for pipelines operating 
under higher-stress. Higher-stress transmission pipelines are typically 
those that transport natural gas across the country from a gathering 
area to a local distribution company. For higher-stress pipelines, the 
industry consensus standard sets maximum reassessment periods at 5 or 
10 years, depending on operating pressure. PHMSA does not collect 
information in such a way that would allow us to readily estimate the 
percentage of all pipeline miles in highly populated or frequented 
areas that operate under higher pressure. For the 25 operators that we 
contacted, the operators told us that about three- fourths of their 
pipeline mileage in highly populated or frequented areas operated at 
higher pressures. Finally, industry data suggest that in the 
neighborhood of 250,000 miles of the 300,000 miles (over 80 percent) of 
all transmission pipelines nationwide may operate at higher pressure. 

Some operators told us that the 7-year reassessment requirement is 
conservative for pipelines that operate under lower-stress. This is 
especially true for local distribution companies that use their 
transmission lines mainly to transport natural gas under lower 
pressures for several miles from larger cross-country lines in order to 
feed smaller distribution lines. They pointed out, for example, that in 
a lower-pressure environment, pipelines tend to leak rather than 
rupture. Leaks involve controlled, slow emissions that typically create 
little damage or risk to public safety. Most local distribution 
companies we spoke with reported finding few, if any, conditions during 
baseline assessments that would necessitate another assessment within 7 
years. As a result, if the 7-year requirement did not exist, the local 
distribution companies would likely reassess every 15 to 20 years 
following industry consensus standards. Some of these operators often 
pointed out that since third-party damage poses the greatest threat to 
their systems. Operators added that third-party damage can happen at 
any time and that prevention and mitigation measures are the best ways 
to address it.[Footnote 13] 

Operators viewed a risk-based reassessment requirement such as in the 
consensus standard as valuable for public safety. Operators of both 
higher-stress and lower-stress pipelines indicated a preference for a 
risk-based reassessment requirement based on engineering standards 
rather than a prescriptive one-size-fits-all standard.[Footnote 14] 
Such a risk-based reassessment standard would be consistent with the 
overall thrust of the integrity management program. Some operators 
noted that reassessing pipeline segments with few defects every 7 years 
takes resources away from riskier segments that require more attention. 
While PHMSA's regulations require that pipeline segments be reassessed 
only for corrosion problems at least every 7 years using a less 
intensive assessment technique (confirmatory direct assessment) some 
operators point out that it has not worked out that way. They told us 
that, if they are going to the effort of assessing pipeline segments to 
meet the 7-year reassessment requirement, they will typically use more 
extensive testing--for both corrosion and for other problems--than 
required, because doing so will provide more comprehensive information. 
Thus, in most cases, operators plan to reassess their pipelines by 
using in-line inspections or direct assessment for problems in addition 
to corrosion sooner than required under PHMSA's rules.[Footnote 15] 

Services and Tools Are Likely to be Available for Reassessments: 

Most 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. All of the operators reported that they 
plan to rely on contractors to conduct all or a portion of their 
reassessments and some 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. 

Nineteen of the 21 operators that reported both baseline and 
reassessment schedules to us said that that they primarily plan to use 
in-line inspection or direct assessment to reassess segments of their 
pipelines located in highly populated or frequented areas. In-line 
inspection contractors that we contacted report that there is capacity 
within the industry to meet current and future operator demands. Unlike 
the in-line inspection method, which is an established practice that 
many operators have used on their pipelines at least once prior to the 
integrity management program, the direct assessment method is new to 
both contractors and operators. Direct assessment contractors told us 
that there is limited expertise in this field and one contractor said 
that newer contractors coming into the market to meet demand may not be 
qualified.[Footnote 16] The operators planning to use direct assessment 
for their pipelines are generally local distribution companies with 
smaller diameter pipelines that cannot accommodate in-line inspection 
tools.[Footnote 17] 

An industry concern about the 7-year reassessment requirement is that 
operators will be required to conduct reassessments starting in 2010 
while they are still in the 10-year period (2003-2012) for conducting 
baseline assessments. Industry was concerned that this could create a 
spike in demand for contractor services resulting from an overlap of 
assessments and reassessments from 2010 through 2012, and operators 
would have to compete for the limited number of contractors to carry 
out both. The industry was worried that operators might not be able to 
meet the reassessment requirement and that it was unnecessarily 
burdensome.[Footnote 18] Most operators that we contacted do not 
anticipate a spike and baseline activity should decrease as they begin 
to conduct reassessments. (See fig. 2.) They predict that operators 
will have conducted a large number of baseline assessments between 2005 
and 2007 in order to meet the statutory deadline for completing at 
least half of their baseline assessments by December 2007 (2 years 
before the predicted overlap). 

Figure 2: Operators' Planned Baseline Assessment and Reassessment 
Schedules: 

[See PDF for image] 

Note: This figure shows the baseline assessments conducted, or planned 
to be conducted as well as the reassessments that are planned in highly 
populated or frequented areas for the 20 of 25 operators we contacted. 
Five operators did not report their reassessment plans. 

[End of figure] 

There has also been a concern about whether baseline assessments and 
reassessments would affect natural gas supply if pipelines are taken 
out of service or operate at reduced pressures when repairs are being 
made. We are addressing this issue and will report on it in the fall. 

PHMSA Has Developed a Reasonable Framework for Its Enforcement Program: 

Recently, PHMSA reassessed its approach for enforcing pipeline safety 
standards in response to our concern that it lacked a comprehensive 
enforcement strategy. In August 2005, PHMSA adopted a strategy that 
focuses on using risk-based enforcement, increasing knowledge of and 
accountability for results, and improving its own enforcement 
activities. The strategy also links these efforts to goals to reduce 
and prevent incidents and damage, in addition to providing for periodic 
assessment of results. While we have neither reviewed the revised 
strategy in depth nor examined how it is being implemented, our 
preliminary view is that it is a reasonable framework that is 
responsive to the concerns that we raised in 2004. 

PHMSA has established overall goals for its enforcement program to 
reduce incidents and damage due to operators' noncompliance. PHMSA also 
recognizes that incident and damage prevention is important, and its 
strategy includes a goal to influence operators' actions to this end. 
To meet these goals, PHMSA has developed a multi-pronged strategy that 
is directed at the pipeline industry and stakeholders (such as state 
regulators), and ensuring that its processes make effective use of its 
resources. 

For example, PHMSA's strategy calls for using risk-based enforcement 
to, among other things, take enforcement actions that clearly reflect 
potential risk and seriousness and deal severely with significant 
operator noncompliance and repeat offenses. Second, the strategy calls 
for increasing knowledge and accountability for results through such 
actions as (1) soliciting input from operators, associations, and other 
stakeholders in developing and refining regulations, inspection 
protocols, and other guidance; (2) clearly communicating expectations 
for compliance and sharing lessons learned; and (3) assessing operator 
and industry compliance performance and making this information 
available. Third, the strategy, among other things, calls for improving 
PHMSA's own enforcement activities through developing comprehensive 
guidance tools and training inspectors on their use, and effectively 
using state inspection capabilities. 

Finally, to understand progress being made in encouraging pipeline 
operators to improve their level of safety and, as a result, reduce 
accidents and fatalities, PHMSA annually will assess its overall 
enforcement results as well as various components of the program. Some 
of the program elements that it may assess are inspection and 
enforcement processes, such as the completeness and availability of 
compliance guidance, the presentation of operator and industry 
performance data, and the quality of inspection documentation and 
evidence. 

Concluding Observations: 

Our work to date suggests that PHMSA's gas integrity management program 
should enhance pipeline safety, and operators support it. We have not 
identified major issues that need to be addressed at this time. We 
expect to provide additional insights into these issues when we report 
to this Subcommittee and others this fall. 

Because the program is in its early phase of implementation, PHMSA is 
learning how to oversee the program and operators are learning how to 
meet its requirements. Similarly, operators are in the early stages of 
assessing their pipelines for safety problems. This means that the 
integrity management program will be going through this shake down 
period for another year or two as PHMSA and operators continue to gain 
experience. 

Mr. Chairman, this concludes my prepared statement. I would be pleased 
to respond to any questions that you or the other Members of the 
Subcommittee might have. 

GAO Contacts and Staff Acknowledgement: 

For further information on this testimony, please contact Katherine 
Siggerud at (202) 512-2834 or siggerudk@gao.gov. Individuals making key 
contributions to this testimony were Jennifer Clayborne, Anne Dilger, 
Seth Dykes, Maria Edelstein, Heather Frevert, Matthew LaTour, Bonnie 
Pignatiello Leer, James Ratzenberger, and Sara Vermillion. 

FOOTNOTES 

[1] Under integrity management, operators systematically assess the 
portions of their pipelines that are in highly populated or frequented 
areas (such as parks) for safety risks. Although the gas integrity 
management program applies to natural, toxic, and corrosive gases, the 
overwhelming majority of gas pipelines in the United States carry 
natural gas. Our work therefore focuses on natural gas. Transmission 
pipelines transport gas products from sources to communities and are 
primarily interstate. Distribution pipelines (local distribution 
companies) that carry natural gas to ultimate users, such as homes, are 
not subject to the 2002 act unless they are operated by companies that 
also operate transmission pipelines. 

[2] GAO, Pipeline Safety: Preliminary Information on the Office of 
Pipeline Safety's Efforts to Strengthen Its Enforcement Program, GAO-04-
875T (Washington, D.C.: June 16, 2004) and GAO, Pipeline Safety: 
Management of the Office of Pipeline Safety's Enforcement Program Needs 
Further Strengthening, GAO-04-801 (Washington, D.C.: July 23, 2004). 

[3] Standards are technical specifications that pertain to products and 
processes, such as the size, strength, or technical performance of a 
product. National consensus standards are developed by standard-setting 
entities on the basis of an industry consensus. PHMSA's regulations 
incorporate reassessment standards developed by the American Society of 
Mechanical Engineers: Managing the System Integrity of Gas Pipelines 
(ASME B31.8S-2004). 

[4] The information that we obtained from the 25 operators is not 
necessarily generalizable to all operators. 

[5] Operators have reported that about 20,000 miles of pipelines are 
located in highly populated or frequented areas. Operators are required 
to make immediate repairs to their pipelines if they (1) determine the 
remaining strength of the pipe shows a predicted failure pressure of 
less than or equal to 1.1 times the maximum allowable operating 
pressure; (2) identify a dent that has any indication of metal loss, 
cracking, or a stress riser; or (3) determine, in their judgment, the 
assessment results require immediate action. 

[6] Under the 2002 act, operators have until 2012 to complete their 
baseline assessments. However, under the 7-year reassessment 
requirement, operators that started their baseline assessments in 2003 
would then need to reassess those pipeline segments in 2010. 

[7] An incident, for PHMSA reporting purposes, involves a death; injury 
requiring hospitalization; or property damage, including the price of 
natural gas lost during an incident, of $50,000 or more. 

[8] Confirmatory direct assessment uses principles and techniques of 
direct assessment to identify internal and external corrosion of 
pipelines. Under confirmatory direct assessment, operators can meet 
PHMSA's rules by using a single assessment tool, rather than several 
tools or approaches that would provide more comprehensive information. 

[9] In-line inspections are accomplished by running specialized tools 
through pipelines to detect problems, such as reduced wall thickness 
and cracks. 

[10] GAO, Pipeline Safety and Security: Improved Workforce Planning and 
Communication Needed, GAO-02-785 (Washington, D.C.: Aug. 26, 2002). 

[11] Twenty-nine states responded to the survey as of early March 2006. 
Three states indicated that PHMSA information was extremely useful, 15 
states said the information was very useful, 3 states said it was 
moderately useful, 4 said it was somewhat useful, and 4 had no opinion. 

[12] Pipeline operators, for example, told us that, when they run an in-
line inspection tool through a pipeline, they will not collect data 
solely within the boundary of the highly populated or frequented area 
if the insertion and retrieval points for the tool extend beyond the 
highly populated or frequented area. Rather, they gather information on 
the pipeline's condition for the entire distance between the insertion 
and retrieval points because, in doing so, they gather additional 
insights into the condition of their pipeline. 

[13] Prevention and mitigation measures include one-call programs, 
proper marking of the pipeline's location, inspection by air, and 
public education programs. In one-call programs, persons who want to 
dig in an area contact a clearinghouse. The clearinghouse notifies 
pipeline operators and others that someone is going to be digging near 
their pipeline, so that the operator can mark the pipeline's location 
prior to the digging work. 

[14] On a related note, the Congress expressed a general preference for 
technical standards developed by consensus bodies over agency-unique 
standards in the National Technology Transfer and Advancement Act of 
1995. 

[15] Direct assessment is used to identify corrosion and other defects 
in pipelines. It is used when in-line inspection cannot be used and to 
avoid interrupting gas supply to a community fed by a single pipeline. 
Direct assessment involves several steps, including digging holes at 
intervals along a pipeline to examine suspected problem areas. 

[16] To prepare for this hearing, we contacted the Inline Inspection 
Association, one company offering in-line inspection services, and two 
companies offering direct assessment services. 

[17] According to industry estimates, 35 percent of all local 
distribution company pipelines (as measured in miles likely to be 
located in highly populated areas) cannot accommodate an in-line 
inspection tool, compared to only about 4 percent of transmission 
operators' pipelines. 

[18] The 2002 act allows operators to request a waiver from conducting 
reassessments when inspection tools are not available and when 
operators need to maintain product supply. PHMSA has not issued 
guidance on conditions under which it would grant a waiver.