Natural Gas Pipeline Safety: Risk-Based Standards Should Allow Operators to Better Tailor Reassessments to Pipeline Threats
Published: 2006-09-08T00:00:00

Fast Facts:

Highlights:
section_title: Why GAO Did This Study
paragraphs: The Pipeline Safety Improvement Act of 2002 requires that operators (1) assess gas transmission pipeline segments in about 20,000 miles of highly populated or frequently used areas by 2012 for safety threats, such as incorrect operation and corrosion (called baseline assessments), (2) remedy defects, and (3) reassess these segments at least every 7 years. Under the Pipeline and Hazardous Materials Safety Administration's (PHMSA) regulations, operators must reassess their pipeline segments for corrosion at least every 7 years and for all safety threats at least every 10, 15, or 20 years, based on industry consensus standards--and more frequently if conditions warrant. Operators must also carry out other prevention and mitigation measures. To meet a requirement in the 2002 act, this study addresses how the results of baseline assessments and other information inform us on the need to reassess gas transmission pipelines every 7 years and whether inspection services and tools are likely to be available to do so, among other things. In conducting its work, GAO contacted 52 operators that have carried out about two-thirds of the baseline assessments conducted to date.
section_title: What GAO Found
paragraphs: Periodic reassessments of gas transmission pipelines are useful because safety threats can change. However, the 7-year requirement appears to be conservative because (1) most operators found few major problems during baseline assessments, and (2) serious pipeline incidents involving corrosion are rare, among other reasons. Through December 2005 (latest data available), 76 percent of the operators (182 of 241) that had begun baseline assessments reported to PHMSA that their pipelines required only minor repairs. These results are encouraging because operators are required to assess their riskiest segments first. Since operators are also required to repair these problems, the overall safety and condition of their pipelines should be enhanced before reassessments begin. In addition, PHMSA data suggest that serious gas transmission pipeline problems due to corrosion are rare. For example, there have been no deaths or injuries as a result of incidents due to corrosion since 2001. Of the 52 operators contacted that have calculated reassessment intervals, the large majority (20 of 23) told GAO that based on conditions identified during baseline assessments, they could safely reassess their pipelines for corrosion, every 10, 15, or 20 years--as industry consensus standards prescribe unless pipeline conditions warrant an earlier assessment. Sufficient resources may be available for operators' reassessment activities, but some uncertainty exists. For the most part, the 52 operators that GAO contacted expect to be able to obtain the services and tools needed through 2012. However, they expressed some concern about whether enough qualified vendors for the confirmatory and direct assessment methods (above-ground inspections followed by excavations) would be available. Industry associations and GAO attempted to determine the degree to which activity would increase from 2010 to 2012, when operators begin reassessing pipelines while completing baseline assessments. An industry effort showed an increase in assessment and reassessment activity, but GAO's showed a decrease. The reasons for the differences are not clear but may be due, in part, to differences in the operators contacted and the methodologies used in collecting this information.

section_title: Letter
paragraphs: Gas transmission pipelines are one of the nation’s safest modes of freight  transportation:  nationwide about three people have died and about eight  have been injured annually, on average, over the past decade because of  natural gas pipeline incidents from all causes. To enhance the safety of gas  transmission pipelines, the Pipeline Safety Improvement Act of 2002  requires that operators of these pipelines develop programs to assess and  mitigate safety threats, such as leaks or ruptures due to incorrect operation  or corrosion, to pipeline segments that are located in highly populated and  frequently used areas, such as parks.  Specifically, operators are required to  perform baseline assessments on one-half of the gas transmission pipeline  mileage located in these areas by December 2007 and the remainder by  December 2012. Pipeline segments that potentially face the greatest risks  of failure from leaks or ruptures are to be assessed first.
The 2002 act also requires that operators reassess these pipeline segments  for safety threats at least every 7 years. Under flexibility provided by the  act, the federal regulator—the Pipeline and Hazardous Materials Safety  Administration (PHMSA)—requires that operators reassess these pipeline  segments for corrosion damage at least every 7 years in its implementing  regulations, because corrosion is the most frequent cause of failures that  can occur over time. It also incorporated, as mandatory, voluntary industry  consensus standards on maximum reassessment intervals into these  regulations for other types of safety threats. The industry standards require  that operators reassess gas pipelines at least every 10, 15, or 20 years for all  safety risks, depending primarily on the condition of the pipelines and the  pressure under which they operate. If conditions warrant, reassessments  must occur more frequently.
The 2002 act required that we assess the 7-year reassessment requirement.  To do so, we examined (1) the extent to which findings from baseline  assessments and other information inform us about the need to reassess  gas transmission pipelines for safety risks at least every 7 years and (2) the  ability of operators to obtain the services and tools needed to perform the  reassessments. These two topics are the main focus of this report. We also  examined the potential impact of periodic assessments on the nation’s  natural gas supply. (See app. I.)  This report deals mostly with natural gas  transmission pipelines, which represent the overwhelming majority of gas  pipelines.
To understand how the findings from operators’ baseline assessments and  other information inform us about the need to reassess gas transmission  pipelines at least every 7 years, we reviewed laws, regulations, and other  PHMSA guidance. We discussed this issue with PHMSA, other federal  agencies, industry associations, companies that perform research in this  area, state safety representatives, and safety advocacy groups. We also  obtained information from 52 gas pipeline operators for which baseline  assessments and reassessments could have the greatest impact, all else  being equal:  larger and smaller transmission pipelines and local  distribution companies (pipeline companies that take gas from  transmission pipelines and distribute it to end users) with the highest  proportion of pipeline miles in highly populated and frequently used areas  to total system miles. Overall, these operators have assessed about 21  percent of the 20,000 miles of gas transmission pipeline that operators have  reported as being within highly populated or frequently used areas. In  addition, we analyzed data from PHMSA for 241 operators that reported, in  2004 and 2005, on the number of immediate repairs conducted after  completing their baseline assessments. To determine the extent to which  gas transmission pipeline operators and local distribution companies will  likely have the resources to reassess their pipelines at least every 7 years,  we asked operators, inspection tool contractors, and industry associations  about the availability of equipment, equipment operators, and data analysts  to interpret results. We also synthesized the information from the 52  operators to determine the aggregate level of actual and planned  assessments and reassessments through 2012 and compared our findings  with the results from an Interstate Natural Gas Association of America and  American Gas Association data collection effort on the same topic. As part  of our work, we assessed the internal controls and the reliability of the data  elements needed for this engagement, and we determined that the data  elements were sufficiently reliable for our purposes. We performed our  work between August 2005 and August 2006 in accordance with generally  accepted government auditing standards. (See app. II for additional details  on our scope and methodology.)
subsections: section_title: Background
paragraphs: The United States has about a 295,000-mile network of gas transmission  pipelines that are owned and operated by approximately 900 operators.  These pipelines are important to the nation because they transport nearly  all the natural gas used, which provides about a quarter of the nation’s  energy supply. Pipelines do not experience many of the safety threats faced  by other forms of freight transportation because they are mostly  underground; but they are subject to failures that occur over time—such as  leaks and ruptures resulting from corrosion or welding defects—and  failures that are independent of time—such as damage from excavation,  land movement, or incorrect operation.
For the most part, two types of pipelines transport gas products:  (1) gas  transmission pipelines and (2) local distribution pipelines. Gas  transmission pipelines typically move gas products over long distances  from sources to communities and are primarily interstate. They typically  operate at a higher stress level (higher operating pressure in relation to  wall strength). By contrast, local distribution pipelines receive gas from  transmission pipelines and distribute it to commercial and residential end  users. Local distribution pipelines, which are primarily intrastate, typically  operate under lower-stress conditions. Local distribution companies may  also operate small portions of transmission pipelines—typically under  lower stress—and are therefore subject to the assessment and  reassessment requirements of the Pipeline Safety Improvement Act of  2002.
Before the 2002 act, operators were subject to PHMSA’s minimum safety  standards for the design, construction, testing, inspection, operation, and  maintenance of gas transmission pipelines; these standards are applied to  all pipelines. However, this approach does not account for differences in  the kinds of threats and the degrees of risk that 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; but PHMSA’s safety standards do not take these threats into account in a systematic way. By contrast, the risk-based  approach of the 2002 act—called the integrity management approach— requires pipeline operators to develop programs to systematically identify  threats and mitigate risks to gas transmission pipeline segments located in  highly populated or frequently used areas. In addition to PHMSA’s  integrity management program, operators must still meet the minimum  safety standards.
As of December 2005 (latest data available), 447 gas pipeline operators  reported to PHMSA that about 20,000 miles of their pipelines (about 7  percent of all gas transmission pipeline miles) lie in highly populated or  frequently used areas. Individual operators reported that they have as many  as about 1,600 miles and as few as 0.02 miles of transmission pipeline in  these areas.
Under PHMSA’s regulations, gas pipeline operators may use any of three  primary approaches to conduct baseline assessments on pipeline segments  lying in highly populated or frequently used areas.
In-line inspection:  In-line inspection involves running a specialized  tool through the pipeline to detect and record anomalies, such as metal  loss and damage. 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, as in hydrostatic  testing (described below). In-line inspection devices can be run only  from facilities established for launching and retrieving them. These  launching and retrieval locations may extend beyond highly populated  or frequently used areas. Operators will typically gather information  along the entire distance between launching and retrieval locations to  gain additional safety information; this is called over-testing.
Direct assessment:  Direct assessment is a nonintrusive, above-ground  instrument inspection that uses two or more types of diagnostic tools,  such as a close interval survey, at predetermined intervals along the  pipeline. Once the data are analyzed, the operator excavates and  inspects segments of the pipeline suspected to have safety threats.
Hydrostatic testing:  Hydrostatic testing entails sealing off a portion of  the pipeline, removing the gas product, filling 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 form of testing  can damage the pipeline due to high pressure testing. Finally, operators  must be able to dispose of large quantities of water in an  environmentally responsible manner.
Under PHMSA’s regulations, which incorporate voluntary industry  consensus standards for managing the system integrity of gas pipelines,  operators must reassess their gas transmission pipeline segments for safety  threats overall at least every 10, 15, or 20 years (consistent with industry  consensus standards), depending on the condition of the pipelines and the  stress under which the pipeline segments are operated. PHMSA’s  regulations allow operators to limit the statutorily required 7-year  reassessment to corrosion damage. In performing reassessments to meet  the 7-year requirement, operators may employ a technique called  confirmatory direct assessment. This technique is similar to direct  assessment; however, operators are required to use only one type of  assessment tool, rather than at least two types required under direct  assessment. According to PHMSA, it allowed this more limited assessment  because the 7-year reassessment for corrosion confirms the acceptable  integrity of a gas transmission pipeline, already ensured by assessments  and reassessments for safety threats conducted at 10-, 15-, or 20-year  intervals under the industry consensus standards incorporated in the  agency’s regulations. (See fig. 2.)  About 2010, operators will be expected to  begin reassessing some segments of their pipelines for corrosion under the  7-year reassessment requirement while they are completing baseline  assessments of other segments—called “the overlap.”
It is important to note that the reassessment intervals under the industry  consensus standards, the 7-year reassessment requirement for corrosion,  and PHMSA’s regulations for time-dependent threats represent the  maximum number of years between reassessments. If pipeline conditions  dictate more frequent reassessments—for example, 5 or fewer years—then  pipeline operators must do so to comply with PHMSA’s regulations. In  addition, between reassessments, operators must continually ensure that  their gas transmission pipelines are safe. PHMSA’s regulations require all  operators—whether or not they are located in highly populated or  frequently used areas to patrol their pipelines, survey for leakage, maintain  valves, ensure that corrosion-preventing cathodic protection is working properly, and take prevention and mitigation measures to  prevent excavation damage.
PHMSA, within the Department of Transportation, attempts to ensure the  safe operation of pipelines through regulation, industry consensus  standards, research, education (e.g., to prevent excavation-related  damage), oversight of the industry through inspections, and enforcement,  when safety problems are found. PHMSA employs about 165 people in its  pipeline safety program, about half of whom are pipeline inspectors who  inspect operators’ implementation of integrity management programs for  gas and hazardous liquid (e.g., oil, gasoline, and anhydrous ammonia)  pipelines, in addition to other more traditional compliance programs.  PHMSA currently has 22 inspectors trained to conduct integrity  management inspections, of which 9 are devoted exclusively to the  program. In addition, PHMSA expects to be assisted by about 180  inspectors in 46 states and the District of Columbia in overseeing intrastate  natural gas transmission pipelines.
section_title: The 7-Year Reassessment Requirement Appears to Be Conservative
paragraphs: Periodic reassessments of pipeline threats are beneficial because threats— such as the corrosive nature of the gas being transported—can change over  time. Baseline assessment findings conducted to date and the generally  safe condition of gas transmission pipelines suggest that the 7-year  requirement appears to be conservative. Most operators of gas  transmission pipelines reported to PHMSA that their baseline assessments  have disclosed 340 problems for which immediate repairs have been made.  This is encouraging because these pipeline segments are supposed to be  the riskiest and few have been systematically assessed until now.  Regarding the industry safety record, the industry is generally safe and no  corrosion-related incidents resulting in deaths or injuries have occurred in  the past 5-1/2 years (from January 2001 through early July 2006) anywhere  in the nation, let alone in highly populated or frequently used areas.  It is  therefore likely to be safe in most cases to allow longer maximum  intervals that coincide with industry consensus standards. PHMSA and  state pipeline agencies plan to inspect all operators’ integrity management  activities, which should serve as a safeguard if longer reassessment  intervals for corrosion are permitted.
subsections: section_title: Most Operators Have Reported That Their Gas Transmission Pipelines Are Mostly Free of Serious Problems
paragraphs: Through December 2005 (latest data available), 76 percent of the operators  (182 of 241) reporting baseline assessment activity to PHMSA told the  agency that their gas transmission pipelines were in good condition and  free of major defects, requiring only minor repairs. (These assessments  covered about 6,700 miles, or about one-third of the nationwide total to be  assessed). The remaining 59 operators reported 340 problems for which  immediate repairs have been completed. (See fig. 1.)
Fifty-two operators (21 percent) reported nine or fewer problems for which  immediate repairs have been completed; and seven operators (3 percent)  reported 10 or more problems. Most of the problems stem from the seven  operators reporting 10 or more problems and concern only a small portion  of their gas transmission pipelines. Specifically, these seven operators  represent nearly 60 percent of the total problems requiring immediate  repairs, and the problems occurred in only 7 percent of 6,700 miles of  baseline assessments conducted. Since PHMSA does not require that  operators report to it the nature of the problems, we do not know how  many of the 340 problems, if any, were due to corrosion.
We contacted 52 operators about the baseline assessments they have  completed and their plans for the rest, and the results were largely  consistent with the overall data reported to PHMSA. Forty-four of these  operators have begun baseline assessments, and 37 of these 44 (84 percent)  told us that they found few safety problems that required reducing pipeline  pressure and performing immediate repairs in response to baseline  assessments in highly populated or frequently used areas. These 44  operators have assessed about 4,100 miles of gas transmission pipeline,  representing about 61 percent of the 6,700 miles of baseline assessment  results reported to PHMSA and about 21 percent of the total number of  pipeline miles in highly populated or frequently used areas nationwide.
It is encouraging that the majority of operators nationwide reported few or  no problems involving immediate repairs, because (1) operators are to  assess pipeline segments facing the greatest risk of failure from leaks or  ruptures first, as required by the 2002 act, and (2) 54 percent of the  operators we contacted (28 of 52) had not conducted risk-based  assessments of their pipeline segments for safety threats prior to the  integrity management program.
Although the PHMSA regulations focus the 7-year reassessment  requirement on corrosion because it is the most frequent cause of time- dependent pipeline incidents, the industry has had a good safety record  prior to and during the initial years of integrity management. It is not  possible to determine which incidents occurred in highly populated or  frequently used areas from summary historical data published by PHMSA.  However, nationwide, these incidents are relatively rare. Over the past 5½  years (from January 2001 through early July 2006), there were 143  corrosion-related incidents over the 295,000-mile transmission system (26  per year, on average)—none of which resulted in death or injury. In  addition, according to PHMSA, during the first 2 years of integrity  management (2004 and 2005), operators reported that corrosion caused 49  leaks, 16 failures, and two incidents involving significant property  damage, but no fatalities and injuries, in highly populated or frequently  used areas.
Both the positive results found during baseline assessments conducted to  date and the overall good safety industry record suggest that gas  transmission pipeline operators that have thus far performed baseline  assessments overall are doing a good job in managing corrosion. Further,  since operators, are required to identify and repair significant problems,  the overall safety and condition of the gas transmission pipeline system  should be enhanced before reassessments begin toward the end of the  decade.
section_title: Operators Support Baseline Assessments and Reassessments but Prefer a Risk-based Reassessment Requirement Over a Fixed One
paragraphs: Because many gas transmission pipelines had never been assessed before  integrity management, operators we contacted pointed out that the new  knowledge gained through baseline assessments represents one of the  greatest benefits of the integrity management program. They also support  reassessments, in part because all operators are subject to the same  requirements. However, most support a risk-based reassessment  requirement, consistent with overall integrity management, over the fixed  7-year requirement prescribed by the 2002 act. Operators also told us they  prefer a risk-based reassessment requirement that is based on research and  historical information. Most operators told us they prefer reassessing  pipelines based on the characteristics and conditions of the pipeline rather  than on the 7-year requirement prescribed in the 2002 act. About 80 percent  of the 52 operators that we contacted prefer that reassessment intervals be  based on the condition and characteristics of the pipeline segment. About  half of these operators (28) expressed a preference for the industry  consensus standard developed by the American Society of Mechanical  Engineers (ASME B31.8S-2004) for setting reassessment intervals for time- dependent threats because it incorporates a risk-based approach (for  pipeline failure) and is based on science and engineering knowledge. This  standard sets reassessment intervals at a maximum of 10 years for high- stress pipeline segments, 15 years for medium-stress segments, and 20  years for low-stress segments. Maximum reassessment intervals, such as  those in the industry consensus standard, incorporate such risk concepts  as built-in safety factors (e.g., wall stress, test pressure, or predicted  failure) and pipeline conditions. The maximum intervals of 10, 15, and 20  years are based on worst-case corrosion growth rates.
The industry consensus standards were developed in 2001 and updated in  2004 based 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. Contributors have been practicing  aspects of risk-based assessments for over 10 years. This standard serves  as a foundation for most sections of PHMSA’s integrity management  regulations. The mechanical engineering society’s standard was reviewed by the American National Standards Institute. The institute found that the  standard was developed in an environment of openness, balance,  consensus, and due process and therefore approved it as an American  National Standard.
While the mechanical engineering standards are voluntary for the industry,  PHMSA incorporated them as mandatory in its gas transmission integrity  management regulations. The mechanical engineering society’s standard  for setting reassessment intervals is not the only industry consensus  standard in PHMSA’s integrity management regulations. The regulations  incorporate other industry consensus standards for using direct  assessment for corrosion, calculating pipeline wall strength, and for  determining temporary reductions in operating pressure. In addition, it is  federal policy to encourage the use of industry consensus standards:  the  Congress expressed a preference for technical standards developed by  consensus bodies over agency-unique standards in the National Technology  Transfer and Advancement Act of 1995. The 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.
Of the 52 operators we contacted, 44 had undertaken baseline assessments,  and 23 of the 44 have calculated their own reassessment intervals. Twenty  of these 23 operators indicated that, based on the conditions they identified  during their baseline assessments, they would reassess their gas  transmission pipelines at maximum intervals of 10, 15, or 20 years—as  allowed by industry consensus standards—if the 7-year reassessment  requirement were not in place. The remaining three operators told us that  they would reassess their pipelines at intervals shorter than the industry  consensus standards but longer than 7 years because of the conditions of  their pipelines. These results add weight to our assessment that the 7-year  requirement may be conservative for most pipelines.
section_title: Safeguards Exist if Industry Consensus Standards for Corrosion Reassessments Are Allowed
paragraphs: Industry consensus standards allow for maximum reassessment intervals  for time-dependent threats of 10, 15, or 20 years only if the operator can  adequately demonstrate that corrosion will not become a threat within the  chosen time interval. If an operator cannot demonstrate that corrosion  does not pose a threat, (e.g., threats posed by shipping gas that is more  corrosive then was shipped previously), then the reassessment must occur  sooner, perhaps at 7 or even 5 or fewer years. Furthermore, according to  industry consensus standards, it typically takes longer than the 10, 15, or 20  years specified in the standard for corrosion problems to result in a leak or  rupture.
As a means of ensuring that assessments and reassessments are done  competently, PHMSA regulations and industry consensus standards require  that operators develop and document the steps they take to ensure the  quality of these activities. This includes ensuring that persons involved are  competent and able to carry out the activities. In addition, operators are  encouraged to conduct internal audits of their quality control approaches  and third-party reviews of their entire integrity management programs.
It is important to note that, in addition to periodic reassessments, operators  must perform prevention and mitigation activities on a continual basis.  PHMSA regulations require that all operators of gas transmission pipelines,  including those outside highly populated or frequently used areas, patrol  their pipelines, survey for leakage, maintain valves, ensure that corrosion- preventing cathodic protection is working properly, and take other  prevention and mitigation measures.
Finally, PHMSA and the state pipeline agencies are inspecting operators’  integrity management plans that were mandated by the 2002 act to provide  their gas transmission pipeline reassessment approaches and intervals,  among other things, to ensure that operators continually and appropriately  assess the conditions of their pipeline segments in highly populated or  frequently used areas. These inspections should serve as a check on  whether operators have identified threats facing these pipeline segments  and determined appropriate reassessment intervals. PHMSA and states  have begun inspections and expect to complete most of the first round no  later than 2009. As of June 2006, PHMSA had completed 20 of about 100  inspections and, as of January 2006, states had begun or had completed 117 of about 670 inspections. Initial results from these inspections show that  operators are doing well in assessing their pipelines and making repairs,  but some need to better document their programs. Based on the initial  inspection results to date, PHMSA and states did not find many issues that  warranted enforcement actions.
section_title: Sufficient Resources May Be Available for Pipeline Reassessments
paragraphs: Although some uncertainty exists, sufficient resources may be available for  operators to reassess their gas transmission pipelines. Operators and  inspection contractors we contacted told us that the services and tools  needed to conduct periodic reassessments will likely be available to most  operators. However, operators expressed their uncertainty about whether  qualified direct assessment and confirmatory direct assessment  contractors will be available. This is important because operators plan to  use these methods to reassess about half of their pipeline mileage.
Contractors told us that they will likely have the capacity to meet demands,  even during periods when baseline assessments and reassessments may  overlap. The severity of this overlap, however, remains unclear. Although  operators that we contacted expect  baseline assessment and reassessment  activity to decrease from 2010 through 2012, an Interstate National Gas  Association of America (INGAA) and American Gas Association (AGA)  polling of their members suggests that activity will rise markedly.
subsections: section_title: Operators Report that Services and Tools Are Likely to Be Available for Reassessments
paragraphs: Thirty-seven out of 52 operators (71 percent), one in-line inspection  association, and all four inspection contractors that provide direct  assessment or in-line inspection tool services that we contacted told us that  the services and tools needed to conduct periodic reassessments will likely  be available to most operators. All but 3 of the operators reported that  they plan to rely on contractors to conduct all or a portion of their  reassessments, and 9 of 52 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  they are several years in the future and operators are concentrating on  baseline assessments.
The 48 operators that reported both baseline and reassessment schedules  told us that they plan to reassess 42 percent of their gas transmission  pipeline miles in highly populated or frequently used areas, using in-line  inspection, and 54 percent of their miles using direct assessment or  confirmatory direct assessment methods. (See fig. 3.)  Operators expect  to assess only 4 percent of their pipeline miles using hydrostatic testing for  several reasons:  (1) this form of testing requires shutting down their  pipelines, (2) other assessment methods yield more robust information  about the condition of their pipelines, (3) hydrostatic testing can weaken or  damage pipelines, and (4) large quantities of water must be disposed of in  an environmentally responsible manner.
The Inline Inspection Association and the two in-line inspection  contractors that we contacted told us that sufficient capacity exists within  the industry to meet current and future operator demands. However,  operators and inspection contractors expressed uncertainty about whether  qualified direct assessment and confirmatory direct assessment  contractors will be available. This is important because operators plan to  use these methods to reassess about half of their gas transmission pipeline  mileage. Unlike the in-line inspection method, which is an established and  less intrusive practice that 27 of 52 operators have used on their pipelines  at least once prior to the integrity management program, two direct  assessment contractors told us that there is limited expertise in this field.  One 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 those with smaller-diameter pipelines that cannot accommodate in-line inspection tools. At a recent INGAA integrity  management workshop, in-line inspection and direct assessment  inspection contractors emphasized that, although they currently have the  resources to meet operator demand and continue to train new inspectors,  operators need to plan ahead to ensure resource availability for future  years, when resources may be more constrained. The workshop also  highlighted technological developments for assessment tools that will  make assessments more efficient. Other stakeholders have told us that  there are new tools being developed that will enable smaller-diameter  pipelines to accommodate in-line inspection tools. For example, the  Department of Energy is developing tiny robotic sensors that can detect  flaws in plastic natural gas pipelines without interrupting the flow of gas.
section_title: The Amount of Assessment Activity Occurring in the Overlap Period Is Uncertain
paragraphs: An industry concern about the 7-year reassessment requirement is that  operators will be required to conduct reassessments starting no later than  2010, while they are still in the 10-year period (2003 through 2012) for  conducting baseline assessments. Industry is concerned that this could  create a spike in demand for contractor services, and operators would have  to compete for the limited number of contractors to carry out both. As a  result, operators might not be able to meet the reassessment requirement.   The information provided by the operators that we contacted shows a  marked overall increase in assessment and reassessment activity in 2010 (a  16 percent increase over 2009 activity) and then a gradual decrease of  activity through 2012. (See fig. 4.)  Operators expect this decrease because  they plan to have completed 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 (3  years before the predicted overlap).
In contrast, INGAA and AGA, after polling their members in 2006, found a  steady overall increase in total expected baseline assessments and  reassessments during the overlap period. INGAA and AGA found that  baseline assessments and reassessments would start to increase in 2009  and rise steadily through 2012. (See fig. 5.)  Assessment activity would  increase by 5 percent in 2010 over the 2009 level; in 2011, by 8 percent over  the preceding year; and in 2012, by 10 percent over the 2011 level.
The difference between our findings and those of INGAA and AGA is not  easy to explain. (See fig. 6.)  Both efforts reported on comparable numbers  of operators (47 for us and 56 for INGAA/AGA) and total transmission  pipeline miles (154,000 for us and 180,000 for INGAA/AGA). To some  extent, the difference may be due to the variations in the pipeline operators  that responded to both efforts. About 72 percent of operators we polled  were different from those polled by INGAA and AGA. However, even where  both efforts collected information from the same operators, the  information was sometimes markedly different. Another reason for the  difference may be due to methodology. For example, we gathered our  information through semistructured interviews with a systematically  selected set of pipeline operators based on larger and smaller transmission  pipelines and local distribution companies with the highest proportion of  pipeline miles in highly populated or frequently used areas to total system  miles, among other things. INGAA and AGA gathered their information by  sending out a self-administered data collection instrument to their  members, and reported results based on those members who responded. In  addition, INGAA and AGA asked operators for data somewhat differently  from methods we used, which may have led to some differences in results.
section_title: Conclusions
paragraphs: Evidence as a result of baseline assessments, the industry’s overall safety  record, the existence of accepted risk-based assessment standards, and  PHMSA’s actions to inspect how operators are identifying corrosion threats  to their pipelines and setting reassessment intervals suggests a risk-based  approach to reassessing gas transmission pipeline segments for corrosion  can achieve the safety objectives of the 2002 act. Evidence gathered to date  suggests that operators that have thus performed baseline assessments are  doing a good job overall managing corrosion. Since the large majority of  pipeline operators that we contacted had not systematically assessed their  transmission pipelines for corrosion risks before the onset of the gas  integrity management program, if corrosion were a rapidly growing  problem, we would have expected a larger proportion of pipelines to report  problems requiring immediate repairs. But, this was not the case.  Furthermore, adopting a risk-based approach to setting reassessment  intervals does not automatically allow operators to reassess their pipeline  segments less frequently than under the 7-year requirement. Rather, if  conditions warrant, an operator would be required to reassess a pipeline  segment as frequently as needed—perhaps even more frequently than  every 7 years. Finally, a risk-based reassessment requirement would be  consistent with the overall approach to integrity management that the  Congress put in place with the 2002 act.
Safeguards are in place to ensure that gas transmission operators  determine reassessment intervals competently. PHMSA regulations and  industry consensus standards require that operators ensure that persons  involved have the experience and expertise to carry out the activities.  Operators are also encouraged to conduct internal audits of their quality  control approaches and third-party reviews of their integrity management  programs. PHMSA and the state pipeline agencies are inspecting operators’  compliance with integrity management reassessment requirements, among  other things, to ensure that operators continually and appropriately assess  the conditions of their gas transmission pipeline segments in highly  populated or frequently used areas.
In summary, the available evidence supports a conclusion that a risk-based  reassessment approach based on technical data, risk factors, and  engineering analyses can achieve the 2002 act’s safety objectives. Such an  approach would provide for reassessments to be tailored to the corrosion  threats faced by the pipeline segment and would not result in  reassessments that are either too infrequent or premature. Evidence to  date suggests that gas transmission pipelines are generally in good shape  based on assessments, following up with immediate repairs and safeguards  being in place to ensure operators determine reassessments appropriately.  In our view, it is not necessary to wait until baseline assessments and a  round of reassessments have been completed before considering whether  to retain or modify the 7-year reassessment requirement.
section_title: Matter for Congressional Consideration
paragraphs: To better align reassessments with safety risks, the Congress should  consider amending section 14 of the Pipeline Safety Improvement Act of  2002 to permit pipeline operators to reassess their gas transmission  pipeline segments at intervals based on technical data, risk factors, and  engineering analyses. Such a revision would allow PHMSA to establish  maximum reassessment intervals, and to require shorter reassessment  intervals as conditions warrant.
section_title: Agency Comments and Our Evaluation
paragraphs: We provided a draft of this report to the Departments of Transportation and  Energy for their review and comment. The Department of Transportation  generally agreed with the report’s findings. The Department of Energy had  no comments.
We are sending copies of this report to congressional committees and  subcommittees with responsibility for transportation safety issues; the  Secretary of Transportation; the Secretary of Energy; the Administrator,  PHMSA; the Assistant Administrator and Chief Safety Officer, PHMSA; the  Deputy Secretary for Natural Gas and Petroleum Technology, Department  of Energy; and the Director, Office of Management and Budget. We will also  make copies available to others upon request. This report will be available  at no charge on the GAO Web site at http://www.gao.gov.
If you have any questions about this report, please contact me at (202) 512- 2834 or siggerudk@gao.gov. Contact points for our Offices of Congressional  Relations and Public Affairs may be found on the last page of this report.  Staff who made key contributions to this report are listed in appendix III.
section_title: Impact of Periodic Reassessments on Natural Gas Supply May Be Less than Foreseen
paragraphs: As the Pipeline Safety Improvement Act of 2002 was being considered, the  Interstate Natural Gas Association of America (INGAA) analyzed the  possible impact of requiring assessments and periodic reassessments and  found that significant disruptions in the natural gas supply and  considerable price increases could occur. A more moderate impact was  predicted in three subsequent analyses—(1) two reviews of the INGAA  study performed for the Pipeline and Hazardous Materials Administration  (PHMSA) by the John A. Volpe National Transportation Systems Center and  by the Department of Energy during the congressional debate over the  pipeline bill, and (2) a post-act PHMSA evaluation of its implementing  regulations. A waiver provision was included in the 2002 act after INGAA’s  study was completed; this may serve as a safety valve if it appears that the  natural gas supply may be disrupted. Finally, our discussions with 50  natural gas pipeline operators also suggest a more moderate potential  impact than INGAA found.
subsections: section_title: INGAA Study Expected Significant Supply Disruptions and Price Increases
paragraphs: INGAA’s study estimated that periodic assessments under integrity  management could lead to a monthly reduction in natural gas supply of  about 1 to 3 percent, along with price increases to customers, among  others, ranging from $382 million to over $1 billion (in 2002 dollars) from  2002 through 2010, depending on the frequency of assessments. Most of  this price increase would be due to supply disruption and some due to  capital expenditures. INGAA considered the monthly reduction in supply to  be significant because it assumed that gas transmission pipelines would be  removed from service during testing and that some areas of the country  would be more vulnerable to supply disruptions than others.
section_title: PHMSA-commissioned Reviews and PHMSA’s Regulatory Evaluation Predict More Moderate Impacts
paragraphs: Both Volpe’s and the Department of Energy’s 2002 reviews of the INGAA  study concluded that gas transmission pipelines would not be significantly  affected by periodic assessments. The reviews, however, did not attempt to  quantify overall estimates of gas disruptions or price impacts. Rather, they  examined the major assumptions in the INGAA study and discussed  whether the study’s results seemed reasonable. PHMSA’s final regulatory  evaluation, which was completed in 2004 to assess the impact of PHMSA’s  regulations on implementing the 2002 act, concluded that transmission  pipelines’ natural gas supply may be somewhat disrupted as a result of  assessments and that cost increases may occur. However, PHMSA  acknowledged that it could not estimate the impact of assessments on gas  prices. In general, the reviews found that the INGAA study’s estimates of  price impacts represent a worst-case scenario because of several overly  pessimistic assumptions. For example, the INGAA study     underestimated the ability of the pipeline network to mitigate  disruptions. INGAA assumed that pipeline assessments would  generally reduce pipeline capacity temporarily, thereby disrupting the  supply and increasing the price of natural gas. Yet, both Volpe’s and the  Department of Energy’s reviews found that the INGAA study did not  sufficiently account for redundancies in the nation’s natural gas  transmission pipeline network. Redundancies enable operators to  mitigate potential disruptions during assessments by rerouting gas  through the network.
Operators we contacted that have higher-stress gas transmission pipelines  generally indicated that their pipeline infrastructure is versatile and  includes such redundancies as parallel pipelines or looping capabilities that  allow gas to flow to customers while portions of the pipeline are assessed  or repaired. (See fig. 7.)  Operators of lower-stress pipelines reported that  they typically use a set of laterals, which feed an interconnected gas  distribution system and allow them to plan around disruptions. In addition,  lower-stress operators can use liquid or compressed natural gas that is  located at their facilities or transported by trucks to specified locations.  Forty-four of the 50 natural gas operators (88 percent) that we contacted  have some type of alternative gas supply, such as storage facilities and  other gas suppliers, to meet customers’ short-term needs.  assumed that a large amount of transmission mileage would  require assessments because of over-testing. The INGAA study  concluded that the number of gas transmission pipeline miles within  highly populated or frequently used areas is only about 5 percent of the  total mileage in the U.S. Nonetheless, the study assumed that over 80  percent of mainline interstate pipeline miles would require assessing,  because the pipeline miles that are located within the highly populated  areas are scattered throughout the pipeline system, and inspection  methods like in-line testing can only be inserted and retrieved in certain  locations that may lie outside highly populated or frequently used  locations. As a result, the study assumed that operators of these  pipelines would assess over 1,500 percent more miles than are within  the highly populated areas. On the basis of comments from industry  groups, PHMSA’s regulatory evaluation assumed that operators would  assess about 625 percent more miles when using in-line inspection  testing and about 25 percent more miles when using hydrostatic testing,  but no over-testing when using the direct assessment method. Baseline  assessment results to date seem to support the lower over-testing  estimate:  as of December 31, 2005, on the basis of performance reports  submitted to PHMSA, operators assessed about 650 percent more miles  overall than are located in highly populated or frequently used areas. assumed that only hydrostatic testing would be used on delivery  laterals. The INGAA study predicted that operators would use only  hydrostatic testing on lateral gas transmission pipelines because it  assumed that very few laterals can accommodate in-line testing. Under  hydrostatic testing, water pressure is used to test the condition of  pipelines; therefore, all of the capacity of a pipeline segment must be  removed for a period of time.
Volpe’s review concluded that this particular assumption represents the  worst possible impact of assessments on lateral pipelines because it  does not allow for the use of in-line testing or direct assessment. Based  on discussions with operators and public comments on PHMSA’s draft  regulatory analysis, the PHMSA regulatory evaluation also assumed  that few operators would use hydrostatic testing. INGAA’s study also  did not address the development of new technologies that could allow  in-line inspection of smaller diameter pipelines. As discussed earlier,  new technology is being developed. Finally, operators we contacted  reported that they do not plan to use hydrostatic testing extensively. As  discussed earlier, only about 4 percent of the mileage will be reassessed  using hydrostatic testing. This testing will typically be over relatively  small lengths of pipeline (from 0.8 to 331 miles).   did not incorporate the ability of operators to obtain waivers.
The INGAA study did not consider the possible impact of a waiver  provision in the 2002 act on maintaining the natural gas supply. This was  understandable because the waiver provision was added to the bills  under consideration after the INGAA study was completed. The act  allows the PHMSA to waive or modify any requirement for operators to  conduct reassessments when they need to maintain product supply as  long as it is consistent with pipeline safety. Twenty-one of the 50 natural  gas operators (42 percent) that we contacted said that they would  consider applying for a waiver, if needed, and 23 (46 percent) told us  that they did not plan to apply for a waiver. Three of the operators were  uncertain, and the remaining three operators did not provide us with a  response. Fourteen of the 26 operators that either did not plan to apply  for a waiver or were unsure about doing so said that it is too early to  determine the need for applying for waivers. They obtained the  necessary equipment to conduct assessments or developed plans for  handling potential natural gas supply disruptions.
section_title: Operators Contacted Found Assessments Have Had Minimal Impact on Supply
paragraphs: Pipeline operators we contacted told us that assessments and repairs of  even their riskiest gas transmission pipelines have not significantly  disrupted the natural gas supplied to customers, such as local distribution  companies and power plants. These 50 natural gas transmission operators  and local distribution companies had assessed about 4,100 miles of pipeline  in highly populated or frequently used areas, as of December 2005 (latest  data available)—or about 21 percent of the total gas transmission mileage  in these areas in the nation and about 62 percent of the pipeline mileage  located in frequently used or highly populated areas assessed to date. Of  the 44 operators that have begun baseline assessments, 26 (59 percent)  indicated that their assessments and repairs did not require them to shut  down their pipelines or reduce their operating pressure. Sixteen operators  (36 percent) reported minor disruptions in their gas supply because they  temporarily shut down pipelines and reduced operating pressure to  conduct assessments or repairs. These operators told us that they used  alternative gas sources, such as liquefied natural gas, to sustain their  customers’ gas supply. The remaining two operators (5 percent) were  located in regions that have limited excess gas capacity. Both operators  reported that they could not meet all of the natural gas needs of their  customers when their pipelines were shut down to perform assessments or  repairs. Some customers, especially those with interruptible contracts,  did not receive gas from the pipelines for several days, but they were able  to obtain gas from alternative sources.
Eleven of the 44 operators were located in regions that have limited excess  gas capacity—the Northeast, the Rocky Mountains, and the Southwest— and reported minor supply disruptions. Five of the 11 operators—all of  which operate lower-stress gas transmission pipelines—reported that none  of these disruptions in natural gas supply were caused by assessments or  repairs. Four operators reported instances in which immediate repairs  caused a reduction in operating pressure; however, they maintained natural  gas supply by relying on alternative gas sources. Since PHMSA does not  require that operators report to it the nature of the problems, we do not  know how many immediate repairs, if any, were due to corrosion. And, as  previously mentioned, 2 of the 11 operators reported natural gas supply  disruptions; although they had to shut down their pipelines due to  assessments or repairs, customers were able to obtain natural gas from  other sources.
In early 2006, INGAA and AGA polled their members about their  experiences with and plans for conducting assessments and reassessments  during off-peak and peak months. Overall, INGAA and AGA found that,  from 2003 to 2012, members plan to conduct 76 percent of their baseline  assessments and reassessments on their gas transmission pipelines (as  measured in miles) during the off-peak spring and summer months, 18  percent in the fall, and 6 percent in the winter. According to an INGAA  official, most of the assessment activity that results in temporary  reductions in gas supply due to repairs being made will likely affect  markets regionally. If assessments occur when pipelines are constrained  for capacity, an increase in delivered gas prices will occur. Overall,  assessments will only affect small groups of the nation’s population, but  they will have a consumer price impact in those affected areas.
Our findings from these operators, while not necessarily representative of  all operators, are encouraging. First, these findings do represent a sizeable  proportion (61 percent) of the mileage assessed to date. Second, the  segments that operators assessed were supposed to be the riskiest  segments (those most susceptible to ruptures or leaks) of the gas  transmission pipelines located in highly populated or frequently used areas.  If so, there should be fewer repairs needed for subsequent baseline  assessments of less risky segments, and hence fewer disruptions in supply.
section_title: Post-act Industry Polling Found Members Plan to Modify and Repair Pipelines, Which May Affect Natural Gas Supply
paragraphs: The 2006 INGAA and AGA polling of their members did not explicitly ask  for the extent to which their members experienced supply disruptions  because of baseline assessments or repairs. However, INGAA and AGA did  ask members to identify the amount of pipeline modifications and repairs  that would be necessary for conducting baseline assessments and  reassessments, activities that could disrupt supply. Overall, INGAA and  AGA found that about 50,000 of the 180,000 miles of gas transmission  pipelines that were reported by responding operators are scheduled for or  have already undergone (1) modifications to allow in-line inspection tools  to access pipeline segments (2) repairs to eliminate major defects or (3)  monitoring for minor problems. According to a senior INGAA official,  assessments and pipeline modifications can generally follow a prearranged  schedule; however, pipeline repairs are unpredictable. Repairs often  require pipelines to be shut down, which could have an effect on natural  gas supply. However, PHMSA officials report that only the worst pipeline  problems require pipelines to be shutdown for repair. From 2003 to 2012,  38,000 of the 50,000 pipeline miles (76 percent) have been scheduled for modifications or repairs during the off-peak spring and summer months to  mitigate supply disruptions.
section_title: Department of Energy Expects Little Disruption in the Natural Gas Supply
paragraphs: Officials from the Office of Oil and Gas within the Department of Energy  told us that the integrity management program, including the 7-year  reassessment requirement, is not likely to significantly disrupt the natural  gas supply. They told us that operators have, among other things, sufficient  system redundancies, such as parallel lines, to maintain product supply.  The Department of Energy has completed several regional analyses of the  possible effects of the disruptions in the natural gas supply caused by such  events as extreme weather conditions (e.g., extended cold periods and  hurricanes). It is completing other analyses as well. However, because  these are being done at the regional level, their results are too broad to help  inform us about more localized and subregional potential disruptions.
section_title: Scope and Methodology
paragraphs: To understand how the findings from operators’ baseline assessments  inform us about the need to reassess gas transmission pipelines at least  every 7 years, we reviewed the requirements of the Pipeline Safety  Improvement Act of 2002 and PHMSA’s implementing regulations. We also  reviewed information about setting reassessment intervals for gas  transmission pipelines, including industry consensus standards for  maximum reassessment intervals developed by the American Society of  Mechanical Engineers, and documents obtained from PHMSA, industry,  and other stakeholders. We discussed this issue with officials from PHMSA,  other federal agencies, industry associations, companies that perform  research in this area, state safety representatives, and safety advocacy  groups. (These organizations are listed at the end of this appendix.)
We also analyzed data from PHMSA on the number of immediate repairs  reported by operators as a result of baseline assessments conducted  through December 2005 (latest data available) and the number of natural  gas pipeline incidents reported to PHMSA.
We contacted 52 pipeline operators (50 natural gas and 2 hydrogen  operators) from among the 447 operators that reported that they operate  gas transmission pipelines in highly populated or frequently used areas.  Forty-four of these operators have begun baseline assessments. We  selected those operators for which the baseline assessments and  reassessments could be expected to have the greatest impact, all else being  equal:  larger and smaller transmission pipelines and local distribution  companies with the highest proportion of pipeline miles in highly  populated or frequently used areas to total system miles. We also selected  operators located in three regions of the country that several studies and  our stakeholders consider to be vulnerable to energy supply disruptions:   the Northeast, the Southwest, and the Rocky Mountains.
The 52 operators reported that they have assessed about 4,100 of the 6,700  miles (61 percent) of pipeline segments, as of December 2005. Overall,  these operators have assessed about 21 percent of the 20,000 miles of  pipeline that operators have reported as being within highly populated or  frequently used areas. Because we used a nonprobability method of selecting these operators, we cannot project our findings nationwide.   Contacting a larger number of operators or selecting them through a  statistical sample would not have been feasible due to resource and time  constraints. Nonetheless, these 52 operators do represent a substantial  portion of the miles assessed to date and of the total number of reported  miles of pipeline in highly populated or frequently used areas.
For these 52 operators, we conducted semistructured interviews to collect  qualitative and quantitative information on the degree to which they found  anomalies during the baseline assessments and, based on these results, the  frequency with which they would reassess these pipeline segments under  American Society for Mechanical Engineers standards for managing the  system integrity of gas pipelines (ASME B31.8S-2004) if the 7-year  reassessment requirement were not in place. As part of our work, we asked  operators to identify the steps that they take to ensure the quality of their  baseline assessments and reassessments, such as ensuring that competent  persons are involved in determining reassessment intervals and conducting  periodic internal or third-party reviews of their integrity management  programs, as recommended by PHMSA regulations and industry standards.  We relied on the operators’ professional judgment in reporting on the  conditions they found during their assessments.
To determine the extent to which gas transmission pipeline operators and  local distribution companies will likely have the resources to reassess their  pipelines, at least every 7 years, we synthesized testimonial and  documentary evidence obtained from our discussions with (1) 52 operators  (as described above) and (2) pipeline assessment tool contractors, direct  assessment vendors, and industry associations on the prospective  availability of equipment, equipment operators, and data analysts to  interpret results. We synthesized the information from the 52 operators to  determine the aggregate level of actual and planned assessments and  reassessments through 2012. We compared our findings with the results  from an INGAA/AGA data collection effort, conducted in 2006, on the same  topic. We then discussed our results with INGAA and analyzed the data  obtained from both efforts to try to understand any differences in results.
To assess the reliability of information provided to us from PHMSA,  INGAA, and AGA, we performed a number of analyses. For the information  provided to us from PHMSA, we compared the number of immediate  repairs operators reported to us to the number of immediate repairs they  reported to PHMSA. To assess the reliability of the data provided to us from  INGAA and AGA, we also compared the reported responses of operators  that were included in INGAA/AGA’s and our efforts. In addition, we  checked the accuracy of INGAA/AGA’s calculations. We determined that  the data were sufficiently reliable for the types of analyses we present in  this report.
subsections: section_title: Other Aspects of Our Work
paragraphs: To determine the potential impact of the 7-year reassessment requirement  on the nation’s natural gas supply, we contacted officials from PHMSA, the  Department of Energy, industry associations, and research firms to discuss  how the potential shutdown of gas transmission pipelines or operation  under reduced pressure—as a result of baseline assessments,  reassessments, and repairs—might affect the continued supply of natural  gas. We also obtained information from the Department of Energy on the  results of analyses of the overall vulnerability of natural gas supplies in  several regions of the nation to extreme conditions, such as extreme cold  weather.
Further, we asked the 50 natural gas operators that we contacted about the  vulnerability of their pipelines to supply disruption and the potential  impact on customers. This included 11 operators located in the three  regions of the country that have limited excess supply gas capacity. We also  discussed how their baseline assessments and any resulting repairs have  affected their customers to date. Finally, we compared operators’  experiences in performing assessments, reassessments, and repairs to the  assumptions made in the 2002 INGAA study of the potential effects of the  proposed integrity management program, two reviews of this study, and  PHMSA’s final regulatory evaluation. The reviews were performed by the  John A. Volpe National Transportation Systems Center and the Department  of Energy at the request of PHMSA.
section_title: Organizations Contacted
section_title: Contact and Staff Acknowledgments
subsections: section_title: GAO Contact
section_title: Staff Acknowledgments
paragraphs: In addition to the above, James Ratzenberger, Assistant Director; Timothy  Bober; Anne Dilger; Seth Dykes; Timothy Guinane; Brandon Haller; Bert  Japikse; and Matthew LaTour made key contributions to this report.