Gas Pipeline Safety: Preliminary Observations on the		 
Implementation of the Integrity Management Program (27-APR-06,	 
GAO-06-588T).							 
                                                                 
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. This 
testimony also discusses how PHMSA has strengthened its 	 
enforcement program in response to recommendations GAO made in	 
2004.								 
-------------------------Indexing Terms------------------------- 
REPORTNUM:   GAO-06-588T					        
    ACCNO:   A52681						        
  TITLE:     Gas Pipeline Safety: Preliminary Observations on the     
Implementation of the Integrity Management Program		 
     DATE:   04/27/2006 
  SUBJECT:   Accident prevention				 
	     Gas pipeline operations				 
	     Pipeline operations				 
	     Safety regulation					 
	     Safety standards					 

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GAO-06-588T

     

     * Background
     * Early Indications Suggest that Gas Integrity Management Enha
     * 7-Year Reassessment Requirement May be Appropriate for Some
          * Operators Favor a Risk-based, Rather than a One-Size-Fits-Al
          * Services and Tools Are Likely to be Available for Reassessme
     * PHMSA Has Developed a Reasonable Framework for Its Enforceme
     * Concluding Observations
     * GAO Contacts and Staff Acknowledgement
          * Order by Mail or Phone

Testimony

Before the Subcommittee on Energy and Air Quality, Committee on Energy and
Commerce, House of Representatives

United States Government Accountability Office

GAO

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

Thursday, April 27, 2006

GAS PIPELINE SAFETY

Preliminary Observations on the Implementation of the Integrity Management
Program

Statement of Katherine Siggerud, Director Physical Infrastructure Issues

GAO-06-588T

GAO reposted the Web version of this testimony on April 28, 2006, to
reflect changes on the highlights page and page 18. The original version
was not updated to provide the latest data to the highlights page. In
addition, a correction was made on page 18 under Figure 2, the word "five"
was replaced with "three." The sentence should say, "Three operators did
not report their reassessment plans."

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 agencies, pipeline inspection contractors, and consensus
standards organizations.3 In addition, we surveyed the 47 state pipeline
agencies responsible for inspecting intrastate gas transmission pipeline
operators on their plans for conducting inspections of operators'
integrity management programs.4 We also contacted 41 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 60 percent of the miles of pipeline assessed to
date. We relied on pipeline operators' professional judgment in reporting
on the conditions that they found during their assessments of safety
risks. The information that we obtained from the 41 operators is not
necessarily generalizable to all operators. 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 April 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.

2GAO, Pipeline Safety: Preliminary Information on the Office of Pipeline
Safety's Actions to Strengthen Its Enforcement Program, GAO-04-985T
(Washington, D.C.: July 20, 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 13
           interstate 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. Most state pipeline officials
           reported that they have started or will start integrity management
           inspections of intrastate operators this year. While state
           officials reported that they generally agree that integrity
           management enhances public safety, most are facing challenges in
           the areas of staffing and training.

           o  Overall, pipeline operators have reported to PHMSA that, in the
           6,700 miles of pipeline in highly populated or frequented areas
           they have assessed, they have found 338 problems that required
           immediate repair or replacement5-about 1 problem every 20 miles,
           on average. The 41 operators that we contacted-which represent
           about 60 percent 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.6 The 7-year reassessment requirement reflects a
           midpoint in relation to industry standards for pipelines operating
           under higher stress (pipelines with higher operating pressure in
           relation to wall strength) where as the industry standard for
           reassessments is 10 years or less. (The industry standard requires
           that pipelines be reassessed at least every 5 years if all repairs
           are not made. PHMSA's regulations require that repairs be made as
           necessary.) However, operators told us that the 7-year
           reassessment requirement is conservative for pipelines operating
           under lower stress, where as 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 (21 of the 26 we contacted) 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
           would 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 told
           us that requiring that pipelines be reassessed more frequently
           than required under industry standards increases costs-which are
           ultimately passed to consumers-but does not increase safety.
           Operators did not expect that the existence of an "overlap period"
           from 2010 through 2012, when operators will be completing baseline
           assessments and beginning some reassessments at the same time,
           would create problems in finding resources to conduct
           reassessments.7 The existence of an overlap had been an industry
           concern while the 2002 act was being debated.

           o  PHMSA has developed a reasonable enforcement strategy framework
           that is responsive to concerns we raised in 2004 that PHMSA had
           not incorporated into its enforcement strategy key features of
           effective program management-clear program goals, a well- defined
           strategy for achieving those goals, and performance measures
           linked to the program goals. PHMSA's recently developed 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 of and accountability for results by clearly
           communicating expectations for operators' 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 annually over the last 10 years in natural gas
           transmission pipeline incidents. The number of incidents has
           increased from 77 in 1996 to 122 in 2004 and 200 in 2005,
           primarily due to the greater frequency of property damage.8 Much
           of this increase may be attributed to the rise 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 operators of gas transmission pipelines to
           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 any
           defective pipelines. Performing this form of risk-based assessment
           is 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.9 Under these regulations, and
           mostly consistent with industry national consensus standards,10
           operators must also reassess their pipeline segments for safety
           risks at least every 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 are located 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. In
           general, PHMSA retains full responsibility for inspecting and
           enforcing regulations on interstate pipelines but certifies states
           to perform these functions for intrastate pipelines. 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. State pipeline agencies
           have about 325 inspectors, about 100 of which are currently able
           to perform integrity management inspections of intrastate gas
           transmission pipeline operators in 47 states.

           Early Indications Suggest that Gas Integrity Management Enhances
			  Public Safety, but Operators and States 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 have assessed the integrity of some of their pipelines,
           others have not. Consequently, some pipelines have operated 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, to take action to mitigate the threats, and to
           document management practices and decision-making processes.

           Representatives from the pipeline industry, safety advocate
           groups, state pipeline agencies, 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 costs. 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 gathering 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 shared it 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 on 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 semiannually 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 41 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 its commitment to
           compliance with 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 agreed with the need to
           document their policies and procedures, some said that the
           detailed documentation required for every decision is very time
           consuming and does not contribute to the safety of pipeline
           operations. Moreover, they are concerned that they will not know
           if they have enough documentation until their program has been
           inspected. After conducting 13 inspections, PHMSA found that,
           while interstate 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.

           In response to our survey, most state officials indicated that the
           two most challenging areas for them as they begin implementing gas
           integrity management inspections are staffing and training. While
           most state agencies currently have at least two inspectors that
           can perform inspections of operators' integrity management
           programs, some state pipeline officials responded that they do not
           have enough inspectors for the increased workload and/or their
           inspectors have not completed the training required by PHMSA. To
           ensure that inspectors have the technical expertise to conduct
           integrity management inspections, including evaluating operators'
           processes and decisions, PHMSA requires inspectors to complete 4
           classroom and 6 computer-based courses, totaling about 19 days of
           training. Three of the classroom courses are part of PHMSA's core
           training for all inspectors and are generally offered annually.
           The fourth course-a new course that PHMSA established for
           integrity management-was made available to two inspectors from
           each state in 2005 and is now offered when there is sufficient
           demand. The computer-based courses were made available to the
           states starting in February 2005. While the state officials we
           spoke with agree that the training is necessary, they are
           concerned about the amount of time it takes to complete the
           required training and the limited availability of the classroom
           training. We will continue to follow up with state agencies about
           how these challenges will affect their oversight activities.

           I am pleased to report that in response to our 2002
           recommendation,11 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 Web site containing inspection information, and (3)
           providing a series of updates through the National Association of
           Pipeline Safety Representatives. Results from the survey of state
           pipeline agencies (with most of the states responding thus far)
           show that the majority of state agencies believe that
           communication from PHMSA has been very or extremely useful in
           helping them understand their roles and responsibilities in
           conducting integrity management inspections.12

           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 the 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 in highly populated or frequented areas that
           they have assessed-about one immediate repair required for every
           20 miles of pipeline assessed in highly populated or frequented
           areas.13 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.

           We contacted 41 transmission operators and local distribution
           companies about their assessment activities. These operators
           represent about 60 percent of the 6,700 miles assessed nationwide.
           Of these, 38 have begun assessments and 32 (84 percent) told us
           that they found few safety problems that required reducing
           pressure and performing immediate repairs during baseline
           assessments. These assessments covered (1) about 4,100 miles of
           pipeline in highly populated or frequented areas and (2) about
           30,000 miles outside of these areas.14 (See fig. 1.) Twenty-five
           of these 38 operators reported finding pipelines in good condition
           and free of major defects, requiring only minor repairs or
           recoating. Seven of these operators found two or fewer problems
           per 100 miles that require immediate repairs. Finally, six
           operators found five or more immediate repairs per 100 miles
           assessed.15 Operators nonetheless found these assessments valuable
           in determining the condition of their pipelines and finding
           damage. The large proportion of these operators reporting that
           they found no or few problems requiring immediate repair is
           encouraging if they represent assessments of their segments facing
           the greatest risk, as required by the 2002 act.

           [Page Intentionally Left Blank]

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 standards, including reassessment standards, developed by the
American Society of Mechanical Engineers: Managing the System Integrity of
Gas Pipelines (ASME B31.8S-2004) and the National Association of Corrosion
Engineers: Standard Recommended Practice -Pipeline External Corrosion
Direct Assessment (NACE RP0502-2002).

4For the purpose of this statement, we treat the District of Columbia as a
state pipeline agency.

5Operators have reported that about 20,000 miles of pipeline 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. Stress risers are corrosion, gouges, or cracks within or
between dents.

6The standards have been accepted by the American National Standards
Institute, a private, non-profit organization whose mission is to promote
and facilitate voluntary consensus standards and promote their integrity.
The Institute does not approve the technical merits of proposed national
standards. Rather it ensures that proposed national standards are
developed in an environment of openness, balance, consensus, and due
process.

                                   Background

7Under 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.

8An incident, for PHMSA reporting purposes, involves a death; injury
requiring hospitalization; or property damage, including any loss of
natural gas during an incident, of $50,000 or more.

9Confirmatory direct assessment allows for less extensive use of testing
methods and is meant to provide assurance that drastic damage is not
taking place. Confirmatory direct assessment allows an operator to obtain
interim results until it performs a full reassessment.

10As discussed earlier, PHMSA's regulations do not provide for the 5-year
reassessment interval that are contained in the industry national
consensus standards.

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

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

11GAO, Pipeline Safety and Security: Improved Workforce Planning and
Communication Needed, GAO-02-785  (Washington, D.C.: Aug. 26, 2002).

12Of the 46 state agencies that responded, three state agencies indicated
that PHMSA information was extremely useful, 23 state agencies said the
information was very useful, 9 state agencies said it was moderately
useful, 5 said it was somewhat useful, 1 said it was not useful, and 5 had
no opinion.

13Most operators found no or few problems and a handful found more than 10
problems overall requiring immediate repair. We hope to portray these
results when we report to this Subcommittee and others this fall.

14For example, pipeline operators told us that, when they run an in-line
inspection tool through a pipeline, they do 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.

15In figure 1, the results for operator Hi12 show a greater number of
problems requiring immediate repair (per 100 miles assessed) because it
has assessed 11 miles and found 2 of these problems. The other two
operators showing the largest number of problems per 100 miles requiring
immediate repair, Lo25 and Lo26, have assessed 77 miles and 370 miles,
respectively.

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

Note: The Hi and Lo prefixes to the operator designations denote higher
stress and lower stress pipelines, respectively. To prevent distortion, we
excluded 3 of the 41 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.

The results for operator Hi12 show a greater number of problems requiring
immediate repair (per 100 miles assessed) because it has assessed 11 miles
and found 2 of these problems. The other two operators showing the largest
number of problems per 100 miles requiring immediate repair, Lo25 and Lo26
have assessed 77 miles and 370 miles, respectively.

Of the 38 operators that have begun assessment activities, 22 have
calculated reassessment intervals.16 These operators indicated that based
on the conditions that they identified during baseline assessments; they
could reassess their pipelines at intervals of 10, 15, or 20 years - as
allowed by industry consensus standards17 - if the 7-year reassessment
requirement were not in place. In some cases, operators chose to reassess
their pipelines at intervals shorter than the industry standards based on
their own discretion. These baseline assessment findings suggest that
overall-at least for the operators we contacted-the 7-year requirement is
conservative.

16The other 16 operators either (1) have not calculated reassessment
intervals; (2) do not intend to, given the prescriptive federal (7 years)
or state (5 years in Texas) reassessment requirements; or (3) did not
supply us information on their reassessment intervals.

17 As discussed earlier, the development of these standards met the
American National Standards Institute's requirements for openness,
balance, consensus, and due process.

The 7-year reassessment interval represents an approximate midpoint
between the 5- and 10-year industry reassessment requirements for
pipelines operating under higher-stress. (The industry standard requires
that pipelines be reassessed at least every 5 years if all repairs are not
made. PHMSA's regulations require that repairs be made as necessary.)
Higher-stress transmission pipelines are typically those that transport
natural gas across the country from a gathering area to a local
distribution company. Operators pointed out that reassessing their
pipelines in 7 rather than 10 years creates additional costs without an
equivalent gain in safety; that is, if the 7-year interval requirement
were not in place they would not reassess their pipelines for another 3
years consistent with industry standards. Operators added that the costs
of the more frequent reassessments will eventually be passed on to
customers. 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.
In the aggregate, the 41 operators that we contacted told us that more
than three-fourths of their pipeline mileage in highly populated or
frequented areas is operated under higher pressure. 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
under 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 pressure
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 pose little damage
or risk to public safety. Twenty-one of the 26 lower stress operators
(most of which are local distribution companies) we contacted that have
begun assessments reported finding few, if any, conditions during baseline
assessments that would require immediate repair. (See fig. 1 and
accompanying note.) As a result, if the 7-year requirement did not exist,
these local distribution companies would likely reassess every 15 to 20
years, following industry consensus standards. Some of these operators
pointed out that third-party damage poses the greatest threat to their
systems. Operators added that third-party damage, such as dents caused by
excavation, can happen at any time and that prevention and mitigation
measures are the best ways to address it.18

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.19 In addition, 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 the less intensive
assessment technique of 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-both for corrosion and other problems-than required, because doing
so will provide more comprehensive information. Thus, in most cases,
operators plan to reassess their pipelines by using the more extensive
in-line inspections or direct assessment for problems in addition to
corrosion sooner than required under PHMSA's rules.20

18Prevention 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 the pipeline
so that the operator can mark the pipeline's location prior to the digging
work.

19On 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.

20Direct assessment is a four-step procedure used to identify corrosion
and other pipeline defects. First, operators analyze information about the
physical characteristics of a pipeline, such as coating, soil moisture,
and past leaks. Second, operators use one or more tools to examine the
pipeline through the soil in areas identified in the first step. Third,
operators use the results of the above-ground examination to dig holes in
intervals along the pipeline to examine suspected pipeline problem areas.
Finally, operators integrate and analyze information gathered during the
three previous steps to determine when additional digging is necessary and
how often pipeline segments should be reassessed.

Finally, operators are required by PHMSA to take actions in addition to
periodically reassessing their pipelines. Operators must, on an ongoing
basis, evaluate their pipelines by integrating operational data with other
information, including assessment data and risk assessment information, to
assure the integrity of their pipelines. Operators will use the results
from the evaluation to identify and remediate specific pipeline threats
and associated risks.

Services and Tools Are Likely to be Available for Reassessments

Thirty-four of the 41 operators and 4 inspection contractors and 1
association we contacted (85 percent) told us that the services and tools
needed to conduct periodic reassessments will likely be available to most
operators.21 All but one of the operators reported that they plan to rely
on contractors to conduct all or a portion of their reassessments, and
eight of the 41 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
reassessments will take place several years in the future, and operators
are concentrating on baseline assessments.

Thirty of the 38 operators (79 percent) that reported both baseline and
reassessment schedules to us said 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 25 of 41
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. 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.22

21To prepare for this hearing, we contacted the Inline Inspection
Association, two companies 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 is 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.23
However, the information provided by the operators that we contacted does
not suggest a spike and because baseline assessment activity should
decrease as they begin to conduct reassessments. (See fig. 2.) Operators
predict that they 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 -two years before the predicted overlap.

22According 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.

23The 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 38 of 41 operators we contacted.
Three operators did not report their reassessment plans.

There has also been a concern about whether baseline assessments and
reassessments would affect the natural-gas supply if pipelines are taken
out of service or operate at reduced pressure 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

In 2004, we concluded that we could not assess the effectiveness of
PHMSA's enforcement strategy because it had not incorporated key features
of effective program management-clear program goals, a well-defined
strategy for achieving those goals, and performance measures that link to
the program goals.24 In response to our concerns, PHMSA adopted a strategy
in August 2005 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 pipeline 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), ensures 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 of 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 by developing comprehensive guidance tools, training inspectors
on their use, and effectively using state inspection capabilities.

Finally, to understand the 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.

24 GAO-04-801 .

                            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 issues that threaten the overall framework of integrity
management. We expect to provide additional insights into issues involving
state pipeline agency staffing and training and the 7-year reassessment
requirement 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 shakedown 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.

(542090)

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Highlights of GAO-06-588T , a testimony before the Subcommittee on Energy
and Air Quality, Committee on Energy and Commerce, House of
Representatives

April 27, 2006

GASPIPELINE SAFETY

Preliminary Observations on the Implementation of the Integrity Management
Program

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 or
welding defects. 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, and inspects operators of
interstate pipelines, while state pipeline safety agencies generally
inspect operators of intrastate pipelines.

This testimony is based on ongoing work for this Subcommittee and for
other committees, as required by the 2002 act. It provides preliminary
results on the safety effects of (1) PHMSA's gas integrity management
program and (2) the requirement that operators reassess their pipelines at
least every 7 years. GAO expects to issue two reports this fall that will
address these and other topics.

This testimony also discusses how PHMSA has strengthened its enforcement
program in response to recommendations GAO made in 2004.

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 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 acquire about the condition of their pipelines, but they
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. State pipeline officials also agree
that integrity management enhances safety, but are concerned about their
ability to obtain sufficient staff and training to inspect operators'
programs.

The 7-year reassessment requirement represents a midpoint between the 5-
and 10-year industry consensus standard reassessment requirements for
higher stress pipelines (pipelines with higher operating pressure in
relation to wall strength). (However, the industry 5-year interval is less
relevant to the integrity management program because it applies when not
all repairs are made. PHMSA's regulations require that repairs be made as
needed.) The majority of transmission pipelines in the U.S. are estimated
to be higher stress pipelines. However, most operators of lower stress
pipelines told GAO that the 7-year requirement is conservative for their
pipelines because they have found few problems requiring reassessments
earlier than the 15 to 20 years under the industry standard for lower
stress pipelines. 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 told GAO that requiring that pipelines be reassessed
more frequently than required under industry standards increases
costs-which are ultimately passed to consumers-but does not increase
safety. Operators did not expect that the existence of an "overlap period"
from 2010 through 2012, when operators will be finishing their baseline
assessments and beginning some reassessments at the same time, will 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.
*** End of document. ***