Gas Pipeline Safety: Preliminary Observations on the Integrity Management Program and 7-Year Reassessment Requirement
Published: 2006-03-16T00:00:00

Fast Facts:

Highlights:
section_title: Why GAO Did This Study
paragraphs: 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.
section_title: What GAO Found
paragraphs: 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.

section_title: Letter
paragraphs: 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. 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, 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. 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. 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.
Implementation of integrity management is in its early stages as PHMSA’s  regulations were finalized in 2004. Early indications suggest that the gas  integrity management program has enhanced public safety by requiring  that operators identify and address the risks to pipeline segments located  in areas that are most likely to affect public safety. Operators believe that  the primary benefit of the program is the comprehensive knowledge they  must acquire about the condition of their pipelines. However, operators  have raised concerns about (1) their uncertainty over the level of  documentation required by the program and (2) whether the requirement  to reassess their pipelines at least every 7 years contributes to increased  safety. PHMSA’s initial inspections of 11 operators’ integrity management  programs have shown that operators are doing well in assessing their  pipelines and making repairs but that they need to better document their  management practices and decisions.
Overall, pipeline operators have reported to PHMSA that, in the almost  6,700 miles of pipeline they have assessed, they have found 338 problems  that required immediate repair or replacement—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.  The existence of an overlap was an industry concern while the 2002 act  was being debated.
PHMSA has developed a reasonable enforcement strategy framework that  is responsive to the recommendations that we made in 2004. PHMSA’s  strategy is aimed at reducing pipeline incidents and damage through both  direct enforcement and prevention. The strategy entails, among other  things, (1) using risk-based enforcement that clearly reflects potential risk  and seriousness and dealing severely with operators’ significant  noncompliance and repeat offenses; (2) increasing knowledge and  accountability for results by clearly communicating expectations for  operator compliance; (3) developing comprehensive guidance tools, along  with training inspectors on their use; and (4) effectively using state  inspection capabilities.
subsections: section_title: Background
paragraphs: 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. 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. 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.
section_title: Early Indications Suggest that Gas Integrity Management Enhances Public Safety, but Operators Raise Some Concerns About Implementation
paragraphs: 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. Furthermore, in response to our 2002 recommendation,  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.
section_title: 7-Year Reassessment Requirement May be Appropriate for Some Operators but Conservative for Others
paragraphs: 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.
subsections: section_title: Operators Favor a Risk- based, Rather than a One- Size-Fits-All Reassessment Standard
paragraphs: 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. (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.
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.
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. 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.
section_title: Services and Tools Are Likely to be Available for Reassessments
paragraphs: 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. 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.
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.  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).
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.
section_title: PHMSA Has Developed a Reasonable Framework for Its Enforcement Program
paragraphs: 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.
section_title: Concluding Observations
paragraphs: 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.
section_title: GAO Contacts and Staff Acknowledgement
paragraphs: For further information on this testimony, please contact Katherine  Siggerud at (202) 512-2834 or siggerudk@gao.gov. Individuals making key  contributions to this testimony were Jennifer Clayborne, Anne Dilger, Seth  Dykes, Maria Edelstein, Heather Frevert, Matthew LaTour, Bonnie  Pignatiello Leer, James Ratzenberger, and Sara Vermillion.
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