Gas Pipeline Safety: Guidance and More Information Needed before Using Risk-Based Reassessment Intervals
Published: 2013-06-27T00:00:00

Fast Facts:

Highlights:
section_title: Why GAO Did This Study
paragraphs: About 300,000 miles of gas transmission pipelines cross the United States, carrying natural gas from processing facilities to communities and large-volume users. These pipelines are largely regulated by PHMSA. The Pipeline Safety Improvement Act of 2002 established the gas integrity management program, which required gas transmission pipeline operators to assess the integrity of their pipeline segments in high consequence areas by December 2012 and reassess them at least every 7 years.
The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 directed GAO to examine the results of these baseline assessments and reassessments and the potential impact of making the current process more risk-based. GAO analyzed (1) PHMSAs assessment data on repairs made and the appropriateness of the 7-year reassessment requirement, (2) the impact of the 7-year reassessment requirement on regulators and operators, and (3) the potential challenges of implementing risk-based reassessment intervals beyond 7 years. GAO analyzed assessment data; reviewed legislation and regulations; and interviewed pipeline operators, federal and state regulators, and other stakeholders.
section_title: What GAO Found
paragraphs: Baseline assessment and reassessment data collected by the Department of Transportation's (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA) since 2004 show that pipeline operators are making repairs in highly populated or frequented areas ("high consequence areas"). For example, from 2004 to 2009, operators made 1,080 immediate repairs. While operators can use assessment data to determine reassessment intervals for specific pipelines, PHMSA's data are aggregated and cannot indicate an appropriate maximum interval for all pipelines nationwide. Such a determination requires, for example, collaboration of subject matter experts and analysis of technical studies.
The current 7-year reassessment requirement provides a safeguard by allowing regulators and operators to identify and address problems on a continual basis, but is not fully consistent with risk-based practices. The 7-year reassessment requirement is more frequent than the intervals found in industry consensus standards and provides greater assurance that operators are regularly monitoring their pipelines to address threats before leaks or ruptures occur. However, this requirement--which was established in a 2002 act as part of the gas integrity management program rather than by rulemaking--is not fully consistent with risk-based management practices, which ask operators to, for example, use information to identify, assess, and prioritize risks so that resources may be allocated to address higher risks first. While operators are required to determine an appropriate reassessment interval based on the threats to their pipelines in high consequence areas, they must reassess those pipelines at least every 7 years regardless of the risks identified.
Implementing risk-based reassessment intervals beyond 7 years would require a statutory change from Congress and could exacerbate current workload, staffing, and expertise challenges for regulators and operators. For example, PHMSA is facing workload problems with inspections, which could be worsened by allowing operators to use risk-based reassessment intervals beyond 7 years; PHMSA has an initiative under way that could help address this issue. Further, some operators told us that extending reassessment intervals beyond 7 years would likely require additional data analyses over what is currently required. Operators GAO met with varied in the extent to which they currently calculate reassessment intervals and use the results of data analyses. Guidance to calculate reassessment intervals is lacking, and as a result, operators may perform a less rigorous determination of their reassessment intervals at this time. At Congress's request, in 2008 PHMSA described how it would establish and enforce risk-based criteria for extending the 7-year reassessment interval. PHMSA proposed retaining the current 7-year reassessment requirement, but establishing a process by which operators could use risk-based reassessment intervals beyond 7 years if they met certain potential criteria, such as demonstrating sound risk analysis. While PHMSA and GAO have supported the concept of risk-based reassessment intervals beyond 7 years, given the breadth of potential challenges with implementation, more information might help decision-makers better understand the resource requirements for this change. For example, PHMSA has used pilot programs to collect such information and study the effects prior to rule changes.
section_title: What GAO Recommends
paragraphs: DOT should (1) develop guidance for operators to calculate reassessment intervals and (2) collect information on the resources needed to implement risk-based reassessment intervals beyond 7 years. DOT did not agree or disagree with the recommendations, but provided technical comments.

section_title: Letter
paragraphs: About 300,000 miles of transmission pipelines across the United States  carry natural gas from processing facilities to communities and large- volume users, such as power plants and factories. These pipelines, which  are largely regulated by the Department of Transportation’s Pipeline and  Hazardous Materials Safety Administration (PHMSA), are relatively safe  when compared with other modes of transporting hazardous goods (e.g.,  highway and rail). However, when pipelines leak or rupture, the results  can be devastating, including fatalities, injuries, and extensive property or  environmental damage. Such an incident occurred in September 2010 in  San Bruno, California, killing eight people and damaging or destroying  over 100 homes.
The Pipeline Safety Improvement Act of 2002 (2002 act) required PHMSA  to implement a risk-based approach to gas transmission pipeline safety,  an approach known as “integrity management.” The integrity  management program requires operators to, among other things,  systematically identify threats and mitigate risks to pipeline segments  located in “high consequence areas,” which include highly populated or  frequented areas. Specifically, the 2002 act required operators of gas  transmission pipelines to complete a baseline assessment looking for  safety threats to their pipelines in high consequence areas by December  2012, and complete reassessments of those pipelines at least every 7  years, a time frame that some stakeholders feel is too frequent. PHMSA  and state pipeline safety offices conduct inspections and other efforts to  oversee operators’ compliance with this program.
The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011  mandated that GAO examine the results of baseline assessment and  reassessment data for gas transmission pipelines, as well as the impact  to stakeholders of making assessments more risk-based.  This report  contains information on: (1) the extent to which PHMSA’s assessment  data provides information on repairs made and the appropriateness of the  7-year reassessment requirement, (2) the impact of the 7-year  reassessment requirement on regulators and operators, and (3) the  potential challenges of implementing risk-based reassessment intervals  beyond 7 years.
Pub. L. No. 112-90, § 5(g), 125 Stat. 1904, 1909 (2012). generalizable sample of 27 gas transmission pipeline operators that we  selected using several criteria, including the number of pipeline miles in  high consequence areas, recent incidents caused by corrosion, and  geographic location. We also spoke with a non-generalizable sample of 8  state pipeline safety offices that were selected based on several factors,  including total pipeline mileage within the state and geographic location.  We collected additional information from three pipeline operators on their  experience calculating reassessment intervals and conducting  reassessments. For more information on our scope and methodology,  see appendix I.
We conducted this performance audit from July 2012 to June 2013 in  accordance with generally accepted government auditing standards.  Those standards require that we plan and perform the audit to obtain  sufficient, appropriate evidence to provide a reasonable basis for our  findings and conclusions based on our audit objectives. We believe that  the evidence obtained provides a reasonable basis for our findings and  conclusions based on our audit objectives.
subsections: section_title: Background
paragraphs: The United States has a network of about 300,000 miles of gas  transmission pipelines that are owned and operated by approximately 900  operators. These pipelines, which are primarily interstate, typically move  gas products over long distances from sources to communities, and tend  to operate at the highest pressures and have the largest diameters of any   Gas transmission pipelines are critical because they  type of pipeline.transport nearly all of the natural gas used in the United States, which  fuels about a quarter of the nation’s energy needs. Pipelines do not  experience many of the safety threats faced by other forms of freight  transportation because they are mostly underground. However, they are  subject to problems that can occur over time (such as leaks and ruptures  resulting from corrosion) or are independent of time (such as damage  from excavation, land movement, or incorrect operation).
PHMSA administers the national regulatory program to ensure the safe  transportation of natural gas and hazardous liquids (e.g., petroleum or  anhydrous ammonia) by pipeline, including developing safety  requirements that all pipeline operators regulated by PHMSA must meet.
In fiscal year 2012, the agency’s total budget was $201 million, about half  of which is for pipeline safety activities. PHMSA’s Office of Pipeline Safety  employs over 200 staff, with about 135 of those staff involved in  inspections and enforcement. In addition, over 300 state inspectors help  oversee pipelines and ensure safety.
Pipeline operators are subject to PHMSA’s minimum safety standards for  the design, construction, testing, inspection, operation, and maintenance  of gas transmission pipelines. However, this approach does not  systematically account for differences in the kinds of threats and the  degrees of risk that individual pipelines face. For example, pipelines  located in the Pacific Northwest are more susceptible to damage from  geologic hazards, such as land movement, than pipelines in some other  areas of the country. Federal efforts to incorporate risk-based concepts  into pipeline management began in earnest in the mid-1990s. For  example, the Accountable Pipeline Safety and Partnership Act of 1996  required the Department of Transportation to establish risk management   The purpose of this effort was “to demonstrate,  demonstration projects. through the voluntary participation by owners and operators of gas  pipeline facilities and hazardous liquid facilities, the application of risk  management; and to evaluate the safety and cost-effectiveness of the  program.”approach to safety: the integrity management program. Integrity  management helps ensure safety by, among other things, using  information to identify and assess risks and prioritizing risks so that  resources may be allocated to address higher risks first. The integrity  management program requires operators to perform a number of  activities, such as identifying high consequence areas and pipelines   These projects helped PHMSA establish a more risk-based  within those areas, as well as identifying the threats facing those  pipelines. PHMSA first implemented integrity management requirements  for hazardous liquid pipeline operators with 500 or more miles of pipelines  in December 2000, followed by hazardous liquid pipeline operators with  less than 500 miles in January 2002. The Pipeline Safety Improvement  Act of 2002 extended the integrity management program to gas  transmission pipelines, which include about 20,000 miles of pipeline  segments located in high consequence areas.subject to PHMSA’s integrity management program, operators must still  meet the minimum safety standards noted above.
As part of the integrity management program, operators are required to  assess the integrity of their pipelines within high consequence areas on a  regular basis using approved methods. Specifically, gas transmission  pipeline operators were required to complete a baseline assessment on  pipeline segments within high consequence areas by December 17,  2012. According to the 2002 act, operators are then required to complete  reassessments of these pipelines at least every 7 years. Gas  transmission pipeline operators completed most baseline assessments by  December 17, 2012, and reassessments are currently under way. From  2004 through December 2011 (the latest data available), baseline  assessments were conducted on over 23,450 miles of gas transmission  pipeline in high consequence areas.
Over 4,470 miles of gas  transmission pipeline in high consequence areas—or about 20 percent of  the pipeline miles that had a completed baseline assessment between  2004 and 2011—were reported as reassessed between 2008 and 2011  (see fig. 1). Among other things, PHMSA’s integrity management  regulations required operators to (1) prioritize their baseline assessments  to assess riskier pipelines first and (2) complete baseline assessments of  these riskier pipelines by December 2007, and all pipelines within high  consequence areas by December 2012. As a result, a small spike in the  mileage assessed occurred in 2007.
Under PHMSA’s regulations, gas transmission pipeline operators may  use any of three primary approaches to conduct assessments:  In-line inspection: In-line inspection involves running a specialized  tool—often known as a smart pig—through the pipeline to detect and  record anomalies, such as metal loss and damage (see fig. 2). In-line  inspection allows operators to determine the nature of any problems  without either shutting down the pipeline for extended periods or  potentially damaging the pipeline. In-line inspection devices can be  run only from specific launch and retrieval points, which may extend  beyond high consequence areas. Operators using in-line inspection  will often gather information along the entire distance between  launching and retrieval locations to gain additional safety information.  Based on PHMSA’s data, the majority of pipeline miles assessed in  2011 (88 percent) were done using in-line inspection.
Direct assessment: Direct assessment is an aboveground  assessment method used to identify problem areas on a pipeline. The  process includes gathering data on potential risks facing the pipeline,  analyzing those data to identify potential problem locations, and then  excavating and directly examining those locations. PHMSA  regulations require that at least two or more aboveground detection  instruments, such as a close interval survey,direct assessment.   be used to constitute a
Hydrostatic testing: Hydrostatic testing entails sealing off a portion of  the pipeline, removing the gas product and replacing it with water, and  increasing the pressure of the water above the rated strength of the  pipeline to test its integrity. If the pipeline leaks or ruptures, the  pipeline is excavated to determine the cause of the failure. Operators  must shut down pipelines to perform hydrostatic testing. Also, this  assessment method can weaken the pipeline due to the high  pressures involved, making it more susceptible to failure later. Finally,  operators must be able to dispose of large quantities of waste water in  an environmentally responsible manner.
According to the operators we spoke with, the costs associated with  performing each of these assessment methods varies greatly. For  example, operators told us that the estimated average cost for conducting  a direct assessment ranges from $5,000 per mile to $500,000 per mile.  The costs vary due to a number of factors, such as the amount of pipeline  mileage to be assessed and the number of digs that must be performed  after completing an assessment to confirm the findings.
PHMSA’s regulations promulgated pursuant to the Pipeline Safety  Improvement Act of 2002 require gas transmission pipeline operators to  reassess their pipelines for all safety risks—such as corrosion,  excavation, land movement, or incorrect operation—at regular intervals  based on industry consensus standards. But the regulations limit the 7- year reassessment requirement in the 2002 act to corrosion damage only  because corrosion is the most frequent cause of failures that can occur  over time. The industry consensus standards adopted in PHMSA’s  regulations require that gas transmission pipeline operators reassess  their pipelines for all safety risks at least every 10, 15, or 20 years,  depending primarily on the condition and operating pressure of the  pipelines, with pressure measured as a percentage of specified minimum   If an operator elects to establish a reassessment interval  yield strength.for all safety risks based on the industry consensus standards, it must—in  order to comply with the 2002 act—perform what is called a “confirmatory  direct assessment” by at least the seventh year to assess corrosion  damage, and then conduct the reassessment for all safety risks at the  interval the operator established. Alternatively, an operator can elect to  perform a reassessment for all safety risks (including corrosion damage)  at least every 7 years in order to comply with both the 2002 act and  PHMSA’s regulations. Figure 3 provides some examples in which an  operator can meet its reassessment requirements, either through  performing (1) a confirmatory direct assessment at year 7 and a  reassessment for all safety risks at a later year that comports with the  industry consensus standards, or (2) a reassessment for all safety risks  every 7 years.
The 7-year reassessment requirement in the Pipeline Safety  Improvement Act of 2002 as well as the reassessment intervals noted in  PHMSA’s regulations and the industry consensus standards are  maximum reassessment intervals: they represent the maximum number  of years between reassessments. If pipeline conditions and risks dictate  more frequent reassessments, then pipeline operators must do so to  comply with PHMSA’s regulations. In addition, between reassessments,  operators must—regardless of whether their pipeline mileage is located in  a high consequence area—patrol their pipelines, survey for leakage,  maintain valves, ensure that corrosion-preventing cathodic protection is  working properly, and take measures to prevent excavation damage.
In general, PHMSA has full responsibility for inspecting interstate  pipelines and enforcing regulations pertaining to them, although some  states are designated as “interstate agents” to assist PHMSA. PHMSA  also has arrangements with the 48 contiguous states, the District of  Columbia, and Puerto Rico to assist with overseeing intrastate pipelines.  State pipeline safety offices are allowed to issue regulations  supplementing or extending federal regulations for intrastate pipelines,  but these state regulations must be at least as stringent as the minimum  federal regulations.
section_title: Data Show Critical Pipeline Repairs Are Being Made, but Cannot Be Used to Determine an Appropriate Maximum Reassessment Interval for All Pipelines Nationwide
subsections: section_title: Assessments Have Resulted in Critical Pipeline Repairs
paragraphs: PHMSA’s baseline assessment and reassessment data from 2004 to  2011 show that pipeline operators have identified and are making critical  repairs in high consequence areas, specifically for conditions requiring  repairs immediately or within one year. For immediate conditions,  operators must make a repair as soon as possible and reduce pipeline  operating pressure or shut down the pipeline until the repair is completed.  A dent in a pipeline wall that also appears to have cracks would be  considered a condition in need of immediate repair. For scheduled  conditions,condition during subsequent assessments for any changes that would  require repair. A dent with a depth of more than two percent of the   operators must make repairs within one year or observe the  pipeline’s diameter located near certain sections of the pipeline wall  would be considered a scheduled condition that must be repaired within  one year. Pipeline operators report annually to PHMSA the number of  immediate and scheduled repairs made on their pipelines that were  identified through assessments. Miles assessed and repairs are reported  in the year they are conducted. PHMSA data show that from 2004 to  2009, pipeline operators reported making 1,080 immediate repairs and  2,261 scheduled repairs (see fig. 4). The data also show that during 2010  and 2011, pipeline operators reported 387 immediate conditions repaired  and 2,246 scheduled conditions repaired. A PHMSA official told us that a  2010 change in reporting requirements resulted in the increase in  reported conditions repaired beginning in 2010.
During this period—2004 through 2011—PHMSA also collected data on  the frequency of incidents, failures, and leaks in high consequence  areas. The average number of incidents in high consequence areas— the most serious of the three events because they can result in fatalities,  injuries, or significant property damage—was 8 per year. When incidents  in high consequence areas occur, they can have a significant impact in  terms of lives lost, injuries, and property damage, as seen with the  incident, noted earlier, in San Bruno, California.
section_title: PHMSA Data Alone Cannot Be Used to Determine a Maximum Reassessment Interval
paragraphs: Individual pipeline operators can use data collected through baseline  assessments and reassessments to determine the appropriate  reassessment interval for pipeline segments on their systems, but using  these data once they have been aggregated to determine a national  maximum reassessment interval is not feasible. Per PHMSA’s  regulations, operators use information on risks specific to their pipeline  and changes in anomalies previously identified to determine the  appropriate reassessment interval for their pipeline segments in high  consequence areas. For example, an operator told us that the company  calculates reassessment intervals for pipeline segments in high  consequence areas using baseline assessment and reassessment data  (when available) to determine the remaining strength of an anomaly and a  corrosion growth rate. Based on these calculations, corrosion should not  grow to unsafe levels before the next reassessment. Pipeline operators  report data to PHMSA that include the miles assessed in high  consequence areas, conditions repaired within high consequence areas,  and the tools used to conduct assessments. These data are reported as a  summary of all pipeline miles for that company. Operators with both  interstate and intrastate pipelines as well as those transporting different  gas products are required to report on each system separately. As a  result, the data collected by PHMSA are highly aggregated and do not  allow comparison of a single pipeline segment over time, or the  determination of a national maximum reassessment interval.
We were asked to compare the number of anomalies noted in PHMSA’s  baseline assessment data with its reassessment data as part of the  mandate for this report in the Pipeline Safety, Regulatory Certainty, and  Job Creation Act of 2011.data collected by PHMSA lack the detail and completeness to make this  comparison:   As described below, the assessment repair
PHMSA’s data do not separate conditions repaired that were  identified from baseline assessments from those identified by  reassessments. Beginning with the 2010 annual report, PHMSA has  used a data collection form that does not require pipeline operators to  differentiate conditions repaired based on whether the condition was  identified during a baseline assessment or a reassessment. A PHMSA  official told us that given the quantity of data pipeline operators are  already required to provide to PHMSA, asking them to report  conditions as either identified during baseline assessments or  reassessments would significantly increase the reporting burden.  Also, as pipeline operators begin their second round of  reassessments, the data will not identify repairs as coming from the  first, second, or later rounds of reassessments. The lack of detail in  PHMSA’s data will make it impossible to compare—amongst all gas  transmission pipeline operators or for a specific pipeline system—the  number of repairs identified during baseline assessments to those  identified during reassessments. Therefore, looking solely at  PHMSA’s data, an observer could not tell whether conditions repaired  have increased or decreased as operators conduct initial and  subsequent reassessments.
Even if repair data were separated based on whether the condition  repaired was identified during a baseline assessment or  reassessment, the first round of reassessments in high consequence  areas may not be complete until the end of 2019. A comparison of  the number of critical repairs identified during baseline assessments  and reassessments would not be possible until these reassessments  are complete.
Further, even if the repair data from baseline assessments and  reassessments could be compared, these data are not sufficient to  determine an appropriate maximum reassessment interval—such as the  7-year reassessment interval established in the Pipeline Safety  Improvement Act of 2002—for all operators for several reasons, including  those listed below:
A decrease or increase in the number of conditions repaired would not  necessarily indicate the appropriateness of the 7-year reassessment  requirement. For example, according to the American Society of  Mechanical Engineers (ASME), a decline in the number of repairs per  mile would indicate the effectiveness of a pipeline operator’s integrity  management plan and not that of the reassessment interval itself.
As mentioned above, the data reported to PHMSA are highly  aggregated. As a result, it is not possible to perform the type of  analysis at the national level that pipeline operators use to determine  reassessment intervals for an individual pipeline segment. For  example, calculating a corrosion growth rate using assessment data is  one way that pipeline operators can determine the appropriate  reassessment interval for a pipeline segment. This calculation  requires information about the history, condition, environment, and the  characteristics of individual anomalies found on that individual pipeline  segment. PHMSA’s assessment data do not have that level of  necessary detail, so they cannot be used to determine an appropriate  maximum reassessment interval for the entire gas transmission  pipeline system in the United States. Instead, PHMSA’s data can  provide descriptive information about how much pipeline mileage  operators are assessing and how many repairs are being made.
While the repair data collected by PHMSA are not sufficient to determine  an appropriate maximum reassessment interval for all pipelines in the  United States, an industry standard setting organization has developed  maximum reassessment intervals of 10, 15, or 20 years that are widely  accepted as balanced and transparent. As we reported in 2006, ASME  developed an industry consensus standard—subsequently approved by  the American National Standards Institute —on maximum reassessment  intervals for all safety risks (including corrosion damage) that PHMSA  incorporated into its regulations. ASME based this standard on, among  other things, (1) the experience and expertise of engineers, consultants,  operators, local distribution companies, and pipeline manufacturers; (2)  more than 20 technical studies conducted by the Gas Technology  Institute, ranging from pipeline design factors to natural gas pipeline risk  management; and (3) other industry consensus standards, including the  National Association of Corrosion Engineers standards, on topics such as  corrosion. In addition, it is federal policy to encourage the use of industry  consensus standards: Congress expressed a preference for technical  standards developed by consensus bodies over agency-unique standards   The  in the National Technology Transfer and Advancement Act of 1995.Office of Management and Budget’s Circular A-119 provides guidance to  federal agencies on the use of voluntary consensus standards, including  the attributes that define such standards.
section_title: The 7-Year Reassessment Requirement Provides a Safeguard, but Is Not Fully Consistent with Risk-Based Practices
subsections: section_title: Maximum Reassessment Intervals Provide a Safeguard
paragraphs: Maximum reassessment intervals—such as the 7-year reassessment  requirement—provide a safeguard and allow regulators and operators to  identify and address problems on a continual basis. The 7-year  reassessment requirement as well as the reassessment intervals noted in  the industry consensus standards represent the maximum number of  years between reassessments. If pipeline conditions dictate more  frequent reassessments, then pipeline operators must perform  reassessments more frequently in order to comply with PHMSA’s integrity  management regulations. Both the 7-year reassessment requirement and  the maximum reassessment intervals noted in the industry consensus  standards are likely to identify problems before they result in leaks or  ruptures. For example, according to the industry consensus standards, it  typically takes longer than the 10, 15, or 20 years specified in the  standards for corrosion problems to result in a leak or rupture. Because  the 7-year reassessment requirement is a more frequent interval than  those in the industry consensus standards, it provides greater assurance  that operators are regularly monitoring their pipelines to identify and  address threats before they result in a leak or rupture.
Regulators and operators we spoke with indicated that a maximum  reassessment interval should exist and saw benefits to conducting  periodic assessments of gas transmission pipelines. Regulators—both at  the federal and state levels—told us that overseeing a maximum  reassessment interval is rather straightforward. For example, an inspector  can use operators’ records to verify relatively easily whether the operator  completed an assessment on time. Operators we spoke with also support  maximum reassessment intervals, telling us that in performing baseline  assessments and reassessments they have obtained valuable knowledge  of the condition of their pipeline systems, and that a maximum  reassessment interval can provide a safeguard to compel poor performing  operators to improve the integrity of their pipeline systems.
section_title: The 7-Year Reassessment Requirement Is Not Fully Consistent with Risk- Based Practices
paragraphs: Risk-based management has several key characteristics that help to  ensure safety—it (1) uses information to identify and assess risks; (2)  prioritizes risks so that resources may be allocated to address higher  risks first; (3) promotes the use of regulations, policies, and procedures to  provide consistency in decision making; and (4) monitors performance.  The gas integrity management program is based on risk-based  management practices. For example, it requires operators to integrate  information from various sources, such as assessments, to identify the  risks specific to their pipelines. To prioritize risks for resource allocation,  the gas integrity management program focuses on high consequence  areas and required operators to assess the riskiest segments of their  pipelines first. Our past work has shown the benefits of risk-based  management, including the integrity management program. For  instance, we reported in 2006 that the integrity management program  benefits public safety by supplementing existing safety requirements with  risk-based management principles that focus on safety risks in high  consequence areas.
However, the 7-year reassessment requirement—which was established  by the Pipeline Safety Improvement Act of 2002 and is just one  component of the gas integrity management program—is not fully  consistent with risk-based management practices. For example, the 7- year reassessment requirement does not permit operators to apply the  information that they have collected from their assessments: even though  operators must determine an appropriate reassessment interval based on  the threats facing their pipelines in high consequence areas, they must  reassess those pipelines at least for corrosion threats every 7 years  regardless of the risks identified. While operators can currently use  data—such as pipeline conditions and other information learned from  previous assessments—to determine that more frequent assessments  than every 7 years are required (e.g., every 5 years), operators cannot  bypass the 7-year reassessment requirement if they have data that  shows reassessment intervals longer than 7 years are justified (e.g.,  every 10 years). Rather, operators that choose to establish reassessment  intervals beyond 7 years must still conduct some type of reassessment at  least every 7 years in order to comply with the 2002 act. PHMSA officials  told us that the 7-year reassessment requirement does not take into  account risk, and while it may be an appropriate interval length for some  pipeline systems, it is too short or too long for other systems.
In contrast to these regulations, there are no statutory requirements that  limit risk-based reassessment intervals for operators of a different type of  pipeline, that of hazardous liquids. Under PHMSA’s regulations for the  hazardous liquid integrity management program, operators must perform  assessments of their pipelines within high consequence areas following a  maximum reassessment interval. This reassessment interval—which,  unlike the gas transmission pipeline reassessment interval, was  established by a PHMSA rulemaking using a data analysis—can be  extended if an operator can provide an engineering basis to do so; that is,  operators have the ability to use the information learned from prior  assessments and other efforts to identify and assess the risks facing its  pipelines and determine that a longer reassessment interval is justified.  Because the 7-year reassessment requirement for gas transmission  pipelines was established by statute and not in a PHMSA rulemaking,  PHMSA does not have the authority to modify this requirement without  congressional action.
In 2006, we reported that most of the operators we contacted preferred  that reassessment intervals be based on the conditions and  characteristics of the pipeline segment. In general, the industry  associations we spoke with for this report also preferred risk-based  reassessment intervals instead of the current 7-year reassessment  requirement. In addition, 21 of the 27 operators we spoke with for this  report indicated that they prefer a risk-based reassessment interval  requirement. According to some of these operators, complying with the  current 7-year reassessment requirement without the ability to use risk- based reassessment intervals beyond 7 years may not be an efficient use  of their resources. For example, some operators told us that if they could  reassess their pipeline segments less frequently than every 7 years  without negatively impacting safety, they could potentially devote more  resources to other safety tasks.
PHMSA’s gas transmission integrity management regulations include  provisions that could make reassessments more risk-based, but these  efforts have not seen widespread use, primarily due to the 2002 act’s 7- year reassessment requirement.
PHMSA’s regulations permit operators to use confirmatory direct  assessment to comply with the 2002 act. Operators that choose to  use confirmatory direct assessment are those that have established  reassessment intervals greater than 7 years but no more than those  noted in the industry consensus standards. These operators perform  a confirmatory direct assessment at year 7 to look for corrosion  threats only, followed by a reassessment at the interval the operator  established for all threats facing the pipeline. According to PHMSA  officials, confirmatory direct assessment was included in the  regulations to better align with risk management principles. However,  of the 27 operators with whom we spoke, only 5 told us that they  completed or planned to conduct confirmatory direct assessment.  According to some of the operators we spoke with, confirmatory direct  assessment—which looks for corrosion damage only—can be just as  costly and time-consuming as performing a reassessment for all  safety risks and, therefore, the operators chose to perform a  reassessment at the 7-year mark instead. Most of the regulators we  spoke with—both at the federal and state levels—also noted that  operators are generally not using confirmatory direct assessment.
PHMSA’s regulations allow operators with ‘exceptional performance’  to deviate from some of the requirements of the integrity management  regulations. These operators must have completed at least two  assessments (i.e., a baseline assessment and a reassessment) and  have remediated all anomalies found in the most recent assessment.  An operator satisfying all of the exceptional performance criteria is  generally permitted to deviate from most integrity management  regulations. However, in order to comply with the 2002 act and  PHMSA’s regulations, the operator must still perform a confirmatory  direct assessment at least every 7 years. None of the operators we  spoke with are pursuing the exceptional performance option, with  most indicating that because they must complete a confirmatory direct  assessment to identify corrosion problems every 7 years, this option  holds little, if any, benefit.
section_title: Implementing Risk- Based Reassessment Intervals beyond 7 Years Could Exacerbate Current Challenges and Would Benefit from More Information on Resource Requirements
subsections: section_title: Changes to the 7-Year Reassessment Requirement Requires Congressional Action and Could Exacerbate Current Issues with Reviewing and Justifying Reassessment Intervals
paragraphs: Although PHMSA generally agreed in the past that risk-based standards  would allow operators to better tailor reassessments to pipeline threats,  PHMSA cannot change the current 7-year reassessment requirement  unless congressional action occurs because the requirement is in statute.  The reassessment requirement is in the regulation pursuant to the  requirement in the Pipeline Safety Improvement Act of 2002. In 2006, we  recommended that this statutory requirement be amended to permit  operators to reassess at intervals based on risk factors, technical data,  and engineering analyses.
In addition to requiring a statutory change, PHMSA officials noted that a  number of current challenges could potentially be exacerbated by  implementing risk-based reassessment intervals. For instance, inspecting  and evaluating risk-based reassessment intervals beyond 7 years could  create additional workload, staffing, and expertise challenges for  regulators, such as PHMSA and state pipeline safety offices, for example:
PHMSA officials told us that allowing all operators to participate in  risk-based reassessment intervals beyond 7 years could add  significantly to the agency’s workload in terms of inspecting operators’  integrity management programs, including review of their calculated  reassessment intervals. For instance, these evaluations could require  inspectors to spend more time and resources than currently, which  could affect the number of inspections conducted overall. Moreover,  PHMSA has already experienced some workload problems with  inspections, which could be worsened by allowing operators to use  risk-based reassessment intervals beyond 7 years. For example, in  2012, the Department of Transportation’s Office of the Inspector  General reported that PHMSA has recently accumulated a backlog of  integrity management inspections for hazardous liquid operators,  caused in part by the agency redirecting resources to fulfill other  inspection requirements. In response, beginning in 2013, the agency  will implement a new approach to inspections, called integrated  inspections, where an inspector may use data and information about  a specific operator and pipeline system to custom-build a list of  regulatory requirements to evaluate during inspection. For these  integrated inspections, integrity management requirements would be  one of several regulatory requirements inspectors could choose to  focus on. However, the Inspector General’s report noted that  PHMSA’s proposed schedule to implement a number of  enhancements to its inspection program is ambitious and challenging,  and until PHMSA successfully completes the transition, the agency  may not be able to ensure sufficient and consistent oversight of all  integrity management programs.
Officials from state pipeline safety offices we met with noted potential  concerns with staffing and training to effectively evaluate risk-based  reassessment intervals. For example, some state pipeline safety  officials suggested that they would need dedicated staff to evaluate  operators’ results and analyses, while other state officials cited the  current difficulty with enrolling in PHMSA training courses due to long  waiting lists. Also, some operators we interviewed expressed concern  that inspectors from state pipeline safety offices may lack sufficient  training to review these analyses. For example, although state officials  currently inspect operators’ integrity management programs, some  operators told us that inspectors do not typically challenge their  reassessment interval calculations.
Regulating risk-based reassessment intervals beyond 7 years could  be particularly challenging for PHMSA and state pipeline safety offices  because there is a lack of guidance for operators to perform risk  modeling. As a result, operators could use a variety of methodologies  to calculate appropriate reassessment intervals for pipeline systems  and even individual segments. The level of detail and review required  by regulators overseeing these operators would vary depending on  the sophistication of the operators’ analyses.
While current regulations require operators to use engineering and risk  analyses to determine the frequency at which reassessments must be  conducted, operators could face additional challenges in justifying and  calculating risk-based reassessment intervals beyond 7 years. Some  operators told us that risk-based reassessment intervals beyond 7 years  would likely be more labor-intensive and data-driven than the current  regulatory environment. For example, operators would likely have to  provide PHMSA more analyses to justify their calculated reassessment  intervals than currently. Based on our interviews, operators appear to  vary in the extent to which they currently calculate reassessment intervals  and use the results of the data analyses, for example:
Some operators we spoke with told us that they perform a less  rigorous determination of their reassessment intervals and default to  the 7-year interval if they determine that there are no problems with  their pipelines. Also, one operator told us that unless evidence of  corrosion is found on the pipeline segment, the operator does not  perform a comprehensive calculation of the reassessment interval.
Some operators we spoke with calculated reassessment intervals  resulting in 7 years, but still chose to reassess their pipelines more  frequently than their calculations due to identified conditions such as  pipeline coating issues. While such a decision prioritizes the safety of  the pipeline, it also illustrates some of the potential subjectivity  involved with reassessment interval calculations, which may have  accounted for such conditions, but did not ultimately determine a  shorter interval in the analysis. For example, some PHMSA officials  told us that oftentimes there is more than one correct conclusion  based on pipeline data and some operators will choose a more  conservative approach than others and vice versa. Further, some  technical experts told us that risk-based reassessment intervals would  require a higher level of skill and analysis beyond some operators’  current capabilities, thus forcing the operator to seek the assistance of  contractors.
As a result, the challenges operators currently have with justifying and  calculating reassessment intervals, partly because of a lack of guidance  from PHMSA, could be further affected if operators are to use these types  of analyses to justify risk-based reassessment intervals beyond 7 years.  Without guidance for operators to use in determining and calculating  reassessment intervals, operators may use a range of approaches for  determining the relevant risks to their systems, which could then create  potential challenges for regulators with reviewing risk-based  reassessment intervals beyond 7 years and ensuring oversight of these  pipelines.
section_title: PHMSA Has Previously Considered an Approach to Implementing Risk- Based Reassessment Intervals beyond 7 Years, but More Information on Resource Requirements Is Needed
paragraphs: In 2008, PHMSA provided a detailed statement at the request of  Congress to explain how the agency would establish and enforce risk- based criteria for extending the 7-year reassessment interval. According  to PHMSA’s proposal, it would retain the current 7-year reassessment  requirement, but allow for the use of risk-based reassessment intervals  on a case-by-case basis where justified. Congress did not take any action   and PHMSA has  to address this proposal as a result of the 2008 report,neither reviewed nor updated its 2008 report to determine whether that  report’s conclusions remain valid. However, PHMSA’s proposal outlined a  number of steps to establish a process permitting the use of risk-based  reassessment intervals beyond 7 years, for example:
First, PHMSA would establish via rulemaking risk-based criteria that  operators must meet to warrant extending their reassessment  intervals beyond 7 years.
Second, interested operators would have to notify PHMSA (or a state  pipeline safety office for an intrastate transmission pipeline) one year  in advance of the scheduled reassessment and submit information  demonstrating their conformance with the criteria before using risk- based reassessment intervals beyond 7 years. As shown in table 1,  one potential criterion could require some operators to conduct  assessments using in-line inspection or hydrostatic testing (see  appendix II for a longer list of draft criteria provided by PHMSA).
Third, PHMSA would review all the notifications to determine whether   For example, operators would  the criteria in the rule have been met.need to demonstrate through analyses and documentation that their  pipeline segments meet each criterion or provide substantial  justification that any failure to meet a criterion does not increase the  risk of corrosion in the segment. PHMSA would also consider in its  review the specific location of the pipeline segments, the potential  consequences if an accident were to occur at that location, and the  compliance and overall performance history of the operator.
PHMSA officials expected that operators of some types of pipelines would  be more likely to use risk-based reassessment intervals beyond 7 years  than others. For example, PHMSA cited operators that have  demonstrated that their pipe is sound and that their engineering and risk  analysis do not indicate the likelihood of time-dependent integrity  problems occurring during a reassessment interval beyond 7 years.  Although operators support the idea of using risk-based reassessment  intervals beyond 7 years, it is not clear how many operators would be  able to meet the potential criteria established by PHMSA, and PHMSA  officials could not estimate the number either. For example, not all  operators can conduct assessments using in-line inspection or hydrostatic  testing, which is one of PHMSA’s proposed criteria for using risk-based  reassessment intervals. According to the proposal, operators would have  to meet each of the criteria. As a result, the mileage of pipelines that  would be affected by allowing risk-based reassessment intervals beyond  7 years is currently unknown.
In light of the uncertain potential effect on resources and expertise for  both regulators and operators, an effort to implement risk-based  reassessment intervals beyond 7 years may benefit first from PHMSA  obtaining additional information regarding the resource requirements  needed prior to a rule change, such as how the Office of Pipeline Safety  initially established integrity management regulations. For example, the  Accountable Pipeline Safety and Partnership Act of 1996 directed the  Office of Pipeline Safety to establish a demonstration program to test a  risk management approach to pipeline safety. Under the program  envisioned by the legislation, the Secretary sought voluntary participation  by interstate natural gas and hazardous liquid transmission operators in  good standing to demonstrate company-specific risk management plans.  The Secretary then completed a rulemaking that outlined the  demonstration plan’s elements and provided opportunities for full public  participation in the process. As a result, partly on the basis of the  agency’s experience with the risk management demonstration program,  the agency moved forward with a new regulatory approach, known as  integrity management. Similarly, as noted above, PHMSA produced a  report at the request of Congress explaining how the agency would  establish and enforce risk-based criteria for extending the 7-year  reassessment interval. In effect, efforts such as these allowed the agency  to obtain preliminary results and information on the proposed rule such as  the potential benefits and impacts under a variety of conditions before  making a change.
section_title: Conclusions
paragraphs: Gas transmission pipeline assessments and reassessments have  resulted in critical repairs being made. While the 7-year reassessment  requirement has provided a safeguard by helping to identify these  problems before they cause leaks or ruptures, the prescriptive 7-year  reassessment requirement is not fully consistent with the characteristics  of risk-based management promoted by the Pipeline Safety Improvement  Act of 2002. PHMSA has generally agreed that risk-based reassessment  intervals would allow operators to better tailor reassessments to pipeline  threats and operators support this concept. Risk-based reassessment  intervals beyond 7 years would allow operators to use the information  they have collected about their pipeline systems to focus resources on  areas of greatest importance.
PHMSA drafted a process to establish and enforce risk-based criteria for  the potential use of risk-based reassessment intervals in 2008. While this  process would be more consistent with risk management practices,  permitting operators to use risk-based reassessment intervals beyond 7  years would not be without challenges, even if justified using an  engineering basis. First, Congress would have to amend the statutory  requirement mandating the 7-year reassessment interval. In 2006, we  recommended that this statutory requirement be amended to permit  operators to reassess at intervals based on risk factors, technical data,  and engineering analyses. If Congress were to amend the statute, both  federal and state regulators as well as operators anticipate that  overseeing and determining risk-based reassessment intervals beyond 7  years may create workload, staffing, and expertise challenges over what  is currently required. Further, there is a lack of guidance to assist  regulators and operators in developing the risk models currently used to  calculate reassessment intervals. Without such guidance, operators could  use a range of approaches for determining the relevant risk to gas  transmission pipelines, potentially creating challenges with reviewing and  justifying reassessment intervals.
Given these potential challenges, more information might help decision- makers better understand the resource requirements needed in allowing  risk-based reassessment intervals beyond 7 years. In this context,  conducting a study or developing a legislative proposal for a pilot  program, in consultation with Congress, to examine the impact on  regulators and operators from the use of risk-based reassessment  intervals beyond 7 years could help stakeholders—including regulators,  operators, and decision-makers—determine the resource demands of  inspecting and evaluating these efforts. A full evaluation of the challenges  to implementing risk-based reassessment intervals beyond 7 years and  their associated resource requirements could help to identify the most  prudent and effective way to implement risk-based reassessment  intervals. Such an evaluation could help to ensure that the challenges  regulators and operators claim they may face from this change would not  negatively affect safety. Further, a study—similar to the 2008 report  PHMSA prepared at the request of Congress and incorporating lessons  learned since publication of that report—or a legislative proposal for a  pilot program—similar to the one used in developing the integrity  management program—could allow regulators to develop guidance on  calculating risk-based reassessment intervals as well as determine the  impact of these reassessment intervals. As the debate about the use of  risk-based reassessment intervals continues, it is clear that more  information is needed to further the understanding and discussion about  how to address the potential challenges to using risk-based  reassessment intervals beyond 7 years before any change occurs.
section_title: Recommendations for Executive Action
paragraphs: To improve how operators calculate reassessment intervals, we  recommend that the Secretary of Transportation direct the Administrator  for the Pipeline and Hazardous Materials Safety Administration to develop  guidance for operators to use in determining risks and calculating  reassessment intervals.
To better identify the resource requirements needed to implement risk- based reassessment intervals beyond 7 years for gas transmission  pipelines, we recommend that the Secretary of Transportation direct the  Administrator for the Pipeline and Hazardous Materials Safety  Administration to collect information on the feasibility of addressing the  potential challenges of implementing risk-based reassessment intervals  beyond 7 years, for example by preparing a report or developing a  legislative proposal for a pilot program, in consultation with Congress, that  studies the impact to regulators and operators of a potential rule change.
section_title: Agency Comments
paragraphs: We provided the Department of Transportation with a draft of this report  for review and comment. The department did not agree or disagree with  the recommendations, but provided technical comments that we  incorporated as appropriate.
We are sending copies of this report to relevant congressional  committees, the Secretary of Transportation, and other interested parties.  In addition, this report will also be available at no charge on GAO’s  website at http://www.gao.gov.
If you or your staff have any questions about this report, please contact  me at (202) 512-2834 or flemings@gao.gov. Contact points for our  Offices of Congressional Relations and Public Affairs may be found on  the last page of this report. GAO staff who made key contributions to this  report are listed in appendix III.
section_title: Appendix I: Objectives, Scope, and Methodology
paragraphs: Our work for this report focused on gas transmission pipelines in high  consequence areas and the requirement to assess these pipeline  segments at periodic intervals. In particular, this report examines: (1) the  extent to which the Pipeline and Hazardous Materials Safety  Administration’s (PHMSA) assessment data provides information on  repairs made and the appropriateness of the 7-year reassessment  requirement, (2) the impact of the 7-year reassessment requirement on  regulators and operators, and (3) the potential challenges of  implementing risk-based reassessment intervals beyond 7 years.
To address the extent to which PHMSA’s assessment data provides  information on repairs and the appropriateness of the 7-year  reassessment requirement, we reviewed PHMSA’s regulations, prior  GAO reports, and PHMSA data on gas transmission pipelines. We  analyzed the data reported to PHMSA by pipeline operators on, among  other things, age and operating pressure of transmission pipelines;  pipeline miles assessed; tools used to conduct assessments; immediate  and scheduled conditions found during assessments and subsequently  repaired; and incidents, leaks, and failures on gas transmission pipelines  in high consequence areas.
We used two PHMSA data sources in our data analysis: the Gas Integrity  Management Semi-Annual Performance Measures Reports from 2004  through 2009 and the Annual Reports on Natural and Other Gas  Transmission and Gathering Pipeline Systems from 2010 and 2011. From  2004 to 2009, PHMSA collected information on miles assessed, incidents,  leaks, and failures in high consequence areas using the Gas Integrity  Management Semi-Annual Performance Measures Report. Through this  report, PHMSA collected data on baseline assessments and started  collecting data on reassessments in 2008. In 2010, PHMSA discontinued  the Gas Integrity Management Semi-Annual Performance Measures  Report and merged it with the Annual Report on Natural and Other Gas  Transmission and Gathering Pipeline Systems. The updated Annual  Report on Natural and Other Gas Transmission and Gathering Pipeline  Systems added questions on pipeline miles that were baseline assessed  and reassessed; tools used to conduct assessments; conditions identified  and repaired as a result of assessments; and incidents, leaks, and  failures in high consequence areas. One important change in the updated  Annual Report was PHMSA’s new approach to documenting conditions  and repairs identified by baseline assessments and reassessments. Prior  to 2010, pipeline operators reported the number of repairs made on  pipelines to fix problematic conditions identified by the assessments—a  single repair could mitigate multiple problems. For 2010 and later,  pipeline operators were required to report the number of repaired  conditions. Since operators have to report the actual number of problems  found and repaired, PHMSA expected the number of reported repairs to  spike. Due to this reporting change, we cannot compare repair data from  2004 to 2009 to repair data reported in 2010 and later. To assess the  reliability of PHMSA’s gas transmission pipeline data, we spoke with  agency officials about data quality control procedures and reviewed  relevant documentation. We determined that the data were sufficiently  reliable for the purposes of this report, specifically to provide background  information and to describe repairs made in high consequence areas. To  ensure the accuracy of our data analysis, we internally reviewed our  calculations and shared preliminary results with PHMSA to ensure that  we analyzed its data appropriately.
To determine the impact of the 7-year reassessment requirement on  regulators and operators, we reviewed relevant legislation and PHMSA  regulations on integrity management. We also interviewed federal and  state regulators, industry associations, gas transmission pipeline  operators, pipeline safety advocacy and environmental groups, research  firms, a state regulatory association, and technical experts. We selected  27 pipeline operators to interview based on our review of PHMSA data,  specifically looking for pipeline operators with gas transmission pipeline  miles in high consequence areas. We then divided pipeline operators into  six groups based on their mileage in high consequence areas and  whether they had conducted reassessments. We chose 3 to 5 operators  from each of the six groups, with the goal of ensuring diversity across  these and several other characteristics, including the number of recent  incidents caused by corrosion and their geographic location. The  information obtained in these interviews is not generalizable to the entire  population of pipeline operators. We also selected a non-generalizable  sample of eight state pipeline safety offices using PHMSA data to, for  example, identify states with relatively high pipeline mileage while also  achieving geographic diversity. Five of the states we spoke with serve as  interstate agents for PHMSA. To learn about the operations of a gas  transmission pipeline and the logistics of conducting an assessment, we  made two site visits to view a pipeline under construction in Manassas,  Virginia, and to view an in-line inspection tool being used on a pipeline in  Rockville, Maryland.
To determine the potential challenges of implementing risk-based  reassessment intervals beyond 7 years, we reviewed PHMSA  documents. We also questioned federal and state regulators, industry  associations, gas transmission pipeline operators, pipeline safety  advocacy and environmental groups, research firms, a state regulatory  association, and technical experts on the extent pipeline operators use  risk to determine reassessment intervals under the current system, as  well as how expanding the use of risk-based reassessment intervals  beyond 7 years would impact operators and regulators. We collected  additional data from three pipeline operators on their experiences in  calculating reassessment intervals and conducting reassessments. We  selected these three pipeline operators by using PHMSA data to identify  gas transmission pipeline operators with different ranges of mileage in  high consequence areas. We then selected operators that had completed  at least some reassessments and looked for diversity in the following  categories: geographic location, number of pipeline repairs, and tools  used to complete assessments.
subsections: section_title: Organizations Contacted
section_title: Appendix II: Potential Criteria for Risk-Based Reassessment Intervals
paragraphs: In 2008, Congress requested that the Pipeline and Hazardous Materials  Safety Administration (PHMSA) provide a detailed statement to explain  how the agency would establish and enforce risk-based criteria for  extending the 7-year reassessment interval. As part of that request,  PHMSA drafted potential criteria that operators would have to meet in  order to use risk-based reassessment intervals beyond 7 years.noted that the criteria may be further refined as potential rulemaking  proceeds. The draft criteria include:  If the pipeline operates at pressures that are greater than or equal to  30 percent of specified minimum yield strength, it must have been  assessed using in-line inspection or hydrostatic testing.
Most recent in-line inspection assessment shows pipeline to be in  good condition. Few conditions meeting immediate repair criteria were  found and the causative corrosion mechanisms have been identified  and addressed.
Most recent pressure test meets integrity management requirements  and resulted in few leaks/failures or pressure reversals.
Few or no significant corrosion repairs have been made in the  covered segment since the last integrity assessment.
Causes of previously identified significant corrosion defects have  been corrected.
No history of selective seam corrosion (a specialized form of corrosion  associated with older pipelines), or microbiologically induced  corrosion (a mode of corrosion incorporating microbes that react and  cause the corrosion or influence other corrosion processes of metallic  materials).
Pipeline transports tariff quality dry gas (almost pure methane), with  limited upsets introducing electrolyte or other contaminants, in which  case internal corrosion risk has been managed.
Pipeline is coated and cathodically protected (a technique to reduce  the corrosion of a metal surface) and be in good condition. Coating  must meet the requirements in 49 C.F.R. § 192.461 and be in good  condition. Cathodic protection must be demonstrated generally  effective.
No history of stress corrosion cracking (the cracking induced from the  combined influence of tensile stress and a corrosive environment).
Assumed corrosion growth rate is justified and supports the longer  reassessment interval. Calculations of remaining time frame before  pipeline failure are conservative and demonstrate safety for an  extended interval.
Few safety related conditions, leaks, incidents, or failures have  resulted from corrosion, and the causes have been addressed.
History of compliance with corrosion control, integrity management,  operator qualification, and drug and alcohol testing regulations is  good.
Public awareness program meets the requirements in 49 C.F.R. §  192.616.
No open corrective action orders or significant enforcement actions  related to corrosion control program deficiencies affecting the involved  pipeline segments.
Pipeline must have been constructed after 1970 unless demonstration  of good condition is provided.
Environmental conditions in which the affected pipeline segment is  located must not be unusually conducive to corrosion.
section_title: Appendix III: GAO Contact and Staff Acknowledgments
subsections: section_title: GAO Contact
paragraphs: Susan A. Fleming, (202) 512-2834, or flemings@gao.gov.
section_title: Staff Acknowledgments
paragraphs: In addition to the contact named above, Sara Vermillion (Assistant  Director), Sarah Arnett, Russell Burnett, Leia Dickerson, Colin Fallon,  David Hooper, Joshua Ormond, Daniel Paepke, Madhav Panwar, Anne  Stevens, and Adam Yu made key contributions to this report.