Gas Pipeline Safety: Preliminary Observations on the Integrity	 
Management Program and 7-Year Reassessment Requirement		 
(16-MAR-06, GAO-06-474T).					 
                                                                 
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 Congress,
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.						 
-------------------------Indexing Terms------------------------- 
REPORTNUM:   GAO-06-474T					        
    ACCNO:   A49197						        
  TITLE:     Gas Pipeline Safety: Preliminary Observations on the     
Integrity Management Program and 7-Year Reassessment Requirement 
     DATE:   03/16/2006 
  SUBJECT:   Accountability					 
	     Federal regulations				 
	     Gas pipeline operations				 
	     Industrial safety					 
	     Inspection 					 
	     Occupational health and safety programs		 
	     Occupational safety				 
	     Pipeline operations				 
	     Program evaluation 				 
	     Program management 				 
	     Repairs						 
	     Risk assessment					 
	     Safety regulation					 
	     Safety standards					 
	     Strategic planning 				 

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GAO-06-474T

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

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.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,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.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.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.

1Under 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.

2GAO, 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).

In summary:

           o  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.

           o  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 replacement5-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.6
           The existence of an overlap was an industry concern while the 2002
           act was being debated.

           o  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.

           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.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.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.

           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.9 Furthermore, in response to our
           2002 recommendation,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.11

           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.

           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.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.

3Standards 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).

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

5Operators 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.

6Under 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.

                                   Background

7An 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.

8Confirmatory 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.

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

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

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

11Twenty-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.

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

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

12Pipeline 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.

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

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.

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.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.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.15

13Prevention 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.

14On 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.

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.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.17

15Direct 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.

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

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.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).

17According 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.

18The 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.

Figure 2: Operators' Planned Baseline Assessment and Reassessment
Schedules

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.

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 [email protected] . 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.

(542087)

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

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and methodology, click on the link above.

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

March 16, 2006

GAS PIPELINE SAFETY

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

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.

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
*** End of document. ***