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. 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. Under these  regulations, and mostly consistent with industry national consensus  standards, 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,  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.

	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. 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. (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. 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.
Of the 38 operators that have begun assessment activities, 22 have  calculated reassessment intervals. 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 standards — 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.
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.
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. 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.
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. 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.
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.  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.
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. 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.

	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 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.

Summary:
Why GAO Did This Study

About a dozen people are killed or injured in natural gas transmission pipeline incidents each year. In an effort to improve upon this safety record, the Pipeline Safety Improvement Act of 2002 requires that operators assess pipeline segments in about 20,000 miles of highly populated or frequented areas for safety risks, such as corrosion, welding defects, or incorrect operation. Half of these baseline assessments must be done by December 2007, and the remainder by December 2012. Operators must then repair or replace any defective pipelines, and reassess these pipeline segments for corrosion damage at least every 7 years. The Pipeline and Hazardous Materials Safety Administration (PHMSA) administers this program, called gas integrity management. This testimony is based on ongoing work for this Subcommittee and for other committees, as required by the 2002 act. The testimony provides preliminary results on the safety effects of (1) PHMSA's gas integrity management program and (2) the requirement that operators reassess their natural gas pipelines at least every 7 years. It also discusses how PHMSA has acted to strengthen its enforcement program in response to recommendations GAO made in 2004. GAO expects to issue two reports this fall that will address these and other topics. This testimony also discusses how PHMSA has strengthened its enforcement program in response to recommendations GAO made in 2004.

What GAO Found

Early indications suggest that the gas transmission pipeline integrity management program enhances public safety by supplementing existing safety standards with risk-based management principles. Operators have reported that they have assessed about 6,700 miles as of December 2005 and completed 338 repairs for problems they are required to address immediately. Operators told GAO that the primary benefit of the program is the comprehensive knowledge they must acquire about the condition of their pipelines. For some operators, the integrity management program has prompted such assessments for the first time. Operators raised concerns about (1) their uncertainty over the level of documentation that PHMSA requires and (2) whether their pipelines need to be reassessed at least every 7 years. The 7-year reassessment requirement is generally consistent with the industry consensus standard of at least every 10 years (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 lower stress pipelines operators told GAO that the 7-year requirement is conservative for their pipelines 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.