Pipeline Safety: Department of Transportation Needs to Complete Regulatory, Data, and Guidance Efforts
Published: 2015-09-29T00:00:00

Fast Facts:

Highlights:
section_title: Why GAO Did This Study
paragraphs: The nation relies on a pipeline network of more than 2.6 million miles to transport hazardous liquids and natural gas. This network includes gathering pipelines that transport products to processing facilities and transmission pipelines that transport products from processing facilities to users (see figure). Pipeline safety oversight from PHMSA, along with state partners, covers issues such as incident response planning and integrity management. PHMSA uses a risk-based approach to regulate pipelines, resulting in regulation of all transmission pipelines and about 10 percent of gathering pipelines. Specifically, PHMSA does not regulate gathering pipelines that are smaller, operate at lower pressure, and are located in rural areas.
This statement addresses PHMSA's efforts in the areas of (1) gathering pipeline safety, (2) pipeline operator incident response, and (3) assessment of natural gas pipeline integrity. It is based on GAO's March 2012, January 2013, June 2013, and August 2014 reports on pipeline safety and July 2015 updates from PHMSA on its actions to respond to the reports' recommendations.
section_title: What GAO Found
paragraphs: The Department of Transportation's (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA) has begun but not completed efforts to improve pipeline safety in response to GAO's prior recommendations:
Gathering pipelines : In 2012, GAO found that while gathering pipelines that are not regulated by PHMSA were generally considered to present less safety risk than other pipelines, PHMSA did not collect comprehensive data to identify such risks. GAO concluded that such data could help pipeline safety officials and pipeline operators increase the safety of these pipelines by better identifying and quantifying safety risks. In 2014, GAO found that construction of larger, higher-pressure gathering pipelines had increased due to the increased production of oil and gas, raising safety concerns because an incident could affect a greater area than an incident from a smaller, lower-pressure pipeline. PHMSA plans to issue proposed rules in fall 2015 that include collecting data on unregulated gathering pipelines.
Pipeline operator incident response : In January 2013, GAO found that PHMSA's data on operators' incident response times were not reliable, limiting the agency's ability to move to a performance-based approach for incident response. Improved data would allow PHMSA to determine appropriate response times for different types of pipelines, based on location and other factors. PHMSA plans to require changes in operator reporting to improve its incident response data and develop a performance-based standard as part of an upcoming rulemaking.
Gas pipeline assessment : In June 2013, GAO found that a requirement for gas transmission pipeline operators to reassess the integrity of their pipelines every 7 years provided a safeguard that issues were regularly addressed, but was not fully consistent with risk-based practices. A risk-based approach based on individual pipeline characteristics could call for assessments to occur more or less frequently than 7 years. However, implementing intervals longer than 7 years could require additional inspection resources to verify that operators appropriately assessed risk. GAO also found that guidance for calculating assessment intervals was lacking. PHMSA plans to issue guidance in 2016 and is researching the feasibility of risk-based assessments occurring less frequently than every 7 years.
section_title: What GAO Recommends
paragraphs: In its reports, GAO made seven recommendations to DOT to improve pipeline safety data and guidance and to move forward with proposed rulemaking to address safety risks. GAO recommended, for example, that DOT move forward with proposed rulemaking to address risks from newer gathering pipelines. DOT is taking actions to respond to the recommendations.

section_title: Letter
paragraphs: Thank you for the opportunity to participate in this hearing on pipeline  safety. The Department of Transportation’s (DOT) Pipeline and  Hazardous Materials Safety Administration (PHMSA), working in  conjunction with state pipeline safety offices, oversees a vital network of  over 2.6 million miles of pipelines carrying oil and natural gas products to  refineries, businesses, and homes. This network includes gathering  pipelines that convey crude oil and natural gas from production wells to  processing facilities; transmission pipelines that transport the processed  products over long distances to communities and large-volume users; and  distribution pipelines that split off from natural gas transmission pipelines  to deliver gas to residential, commercial, and industrial customers. As you  know, pipelines are a relatively safe means of transporting these  hazardous materials; however, catastrophic incidents can and do occur  when pipelines leak or rupture, resulting in death, injury, and  environmental and property damage. PHMSA establishes regulations that  pipeline operators must follow to construct and maintain pipelines, as well  as prepare for and respond to incidents. Since 2002, PHMSA has  required operators to follow a risk-based approach to pipeline safety. For  example, the Pipeline Safety Improvement Act of 2002 required PHMSA  to implement a risk-based “integrity management” program for natural gas  transmission pipeline safety that required pipeline operators to complete a  baseline safety assessment of their pipelines and complete  reassessments of those pipelines at least every 7 years.
My statement today highlights our past work on:  1) the safety of gathering pipelines, particularly in light of the boom in oil  and natural gas production from shale sources;  2) the ability of transmission pipeline operators to respond to incidents;  and  3) requirements for reassessing the integrity of natural gas transmission  pipelines.
For this statement, we drew from our reports on these topics issued from  2012 through 2014. For these reports, we analyzed PHMSA pipeline  incident data; reviewed pipeline regulations; conducted literature reviews;  and interviewed selected pipeline operators, representatives of safety and  industry groups, state pipeline safety officials, and PHMSA officials. For  the 2012 report on gathering pipelines, we also surveyed state pipeline  safety officials in all 50 states and the District of Columbia. In addition, in  July 2015, we obtained updates from PHMSA on its actions to respond to  the recommendations we made in these reports. Additional information on  the scope and methodology for each report can be found in these reports.  Our work on each pipeline safety report was conducted 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: Pipelines transport roughly two-thirds of domestic energy supplies  through over 2.6 million miles of pipelines across the United States.  These pipelines carry hazardous liquids and natural gas from producing  wells to end users, such as businesses and homes. Within this  nationwide system, there are three main types of pipelines—gathering,  transmission, and gas distribution—managed by about 3,000 operators.  (See fig. 1.)
Gathering pipelines. Gas gathering pipelines collect natural gas from  production areas, while hazardous liquid gathering pipelines collect oil  and other petroleum products. These pipelines then typically transport the  products to processing facilities, which in turn refine the products and  send them to transmission pipelines. Unlike the other types of pipelines,  many of these pipelines have not been subject to PHMSA regulation  because they are generally located in rural areas, are smaller in diameter  than transmission pipelines (traditionally about 2 to 12 inches), and  operate at lower pressures, ranging from about 5 to 800 pounds per  square inch (psi). PHMSA regulates gathering pipelines in nonrural  areas, resulting in regulation of approximately 10 percent of gathering  pipelines.
Transmission pipelines. Transmission pipelines carry hazardous liquid or  natural gas, sometimes over hundreds of miles, to communities and  large-volume users (e.g., factories). For natural gas transmission  pipelines, compression stations located periodically along the pipeline  maintain product pressure. Similarly, pumping stations along hazardous  liquid transmission pipelines maintain product flow. Transmission  pipelines tend to have the largest diameters and pressures of the three  types of pipelines, generally ranging from 12 to 42 inches in diameter and  operating at pressures ranging from 400 to 1440 psi. PHMSA’s  regulations cover all hazardous liquid and natural gas transmission  pipelines.
Gas distribution pipelines. Natural gas distribution pipelines transport  natural gas from transmission pipelines to residential, commercial, and  industrial customers. These pipelines tend to be smaller, sometimes less  than 1 inch in diameter, and operate at lower pressures—0.25 to 100 psi.
PHMSA estimated that in 2014 there were about 200,000 miles of  hazardous liquid pipelines, 302,000 miles of gas transmission pipelines,  18,000 miles of gas gathering pipelines, and 2.2 million miles of gas  distribution pipelines based on annual reports from pipeline operators.
Transporting hazardous liquids and natural gas by pipelines is associated  with far fewer fatalities and injuries than other modes of transportation.  From 2010 to 2014, there was an average of about 14 fatalities per year  for all pipeline incidents reported to PHMSA, including an average of  about 2 fatalities per year resulting from incidents on hazardous liquid and  natural gas transmission pipelines. In comparison, in 2013, 3,964  fatalities resulted from incidents involving large trucks and 703 additional  fatalities resulted from railroad incidents. Yet risks to pipelines exist, such  as corrosion and third-party excavation, which can damage a pipeline’s  integrity and result in leaks and ruptures. A leak is a slow release of a  product over a relatively small area. A rupture is a breach in the pipeline  that may occur suddenly; the product may then ignite, resulting in an  explosion. According to pipeline operators we met with in our previous  work, of the two types of pipeline incidents, leaks are more common but  generally cause less damage. Ruptures are relatively rare but can have  much higher consequences because of the damage that can be caused  by an associated explosion.
PHMSA administers two general sets of pipeline safety requirements and  works with state pipeline safety offices to inspect pipelines and enforce  the requirements. The first set of requirements is minimum safety  standards that cover specifications for the design, construction, testing,  inspection, operation, and maintenance of pipelines. Under PHMSA’s  minimum safety standards, operators are required to have a plan for  responding to an incident that addresses leak detection, coordinating with  emergency responders, and shutting down the affected pipeline segment.  The amount of time it takes to shut down a pipeline segment depends on  the type of valve installed on the pipeline. For example, manual valves  require a person to arrive on site and either turn a wheel crank or activate  a push-button actuator. In contrast, automated valves generally take less  time to close than manual valves. They include remote-control valves that  can be closed via a command from a control room and automatic-shutoff  valves that can close without human intervention based on sensor  readings. PHMSA’s minimum safety standards dictate the spacing of all  valves, regardless of the type of equipment installed to close them.
The second set of requirements is part of a supplemental risk-based  regulatory program termed “integrity management,” whereby operators  are required to systematically identify and mitigate risks to pipeline  segments that are located in “high-consequence areas” where an incident  would have greater consequences for public safety or the environment.
For example, natural gas transmission pipeline operators were required to  assess the integrity of their pipelines within high-consequence areas by  December 2012, repair or otherwise address anomalies found during the  assessment, and reassess these segments at least once every 7 years  thereafter. Integrity management regulations also require that all  transmission pipeline operators consider the use of automated valves  when identifying and mitigating pipeline risks. These requirements have  been in effect for all hazardous liquid pipelines since 2002, for natural gas  transmission pipelines since 2004, and for natural gas distribution  pipelines since 2010.
section_title: Gathering Pipelines Pose Safety Risks That PHMSA Is Working to Address
paragraphs: In our 2012 and 2014 reports, we identified safety risks associated with  gas and hazardous liquid gathering pipelines that PHMSA was planning  to but had not yet addressed through regulatory proposals. In 2012, we  found that PHMSA does not collect comprehensive data on safety risks  associated with gathering pipelines. Although gathering pipelines  generally pose lower safety risks than other types of pipelines, our survey  of state pipeline safety agencies found problems including construction  quality, maintenance practices, unknown or uncertain locations, and  limited or no information on current pipeline integrity as safety risks for  federally unregulated gathering pipelines. Operators of federally  unregulated gathering pipelines are not required by federal law to report  information on such risk factors. Furthermore, the survey, as well as  interviews with other pipeline industry stakeholders, identified land-use  changes—namely urban development encroaching on existing pipeline  rights-of-way—and the increased extraction of oil and gas from shale as  changes in the operating environments that could increase the safety  risks for federally unregulated gathering pipelines. Consequently, federal  and state pipeline safety officials do not know the extent to which  individual operators collect such information and use it to monitor the  safety of their pipelines.
In our 2012 report, we found that the data PHMSA collects for regulated  pipelines help federal and state safety officials and pipeline operators  increase the safety of these pipelines by better identifying and quantifying  safety risks, as well as by implementing mitigation strategies, and  addressing potential regulatory needs. We concluded that collecting such  data about gathering pipelines could facilitate quantitatively assessing the  safety risks posed by unregulated gathering pipelines. We recommended  that PHMSA collect data from operators of federally unregulated onshore  hazardous liquid and gas gathering pipelines subsequent to an analysis  of the benefits and industry burdens associated with such data collection.  We recommended that data collected should be comparable to what  PHMSA collects annually from operators of regulated gathering pipelines  (e.g., fatalities, injuries, property damage, location, mileage, size,  operating pressure, maintenance history, and the causes and  consequences of incidents). In July 2015, PHMSA officials told us that  regulatory proposals the agency plans to issue for both natural gas and  hazardous liquid pipelines will call for collecting data on unregulated  gathering pipelines through both annual reports and accident/incident  reports. As of September 2015, DOT estimated that Notices of Proposed  Rulemaking on these issues would be published in October 2015.
We also found in our 2012 report that a small number of state pipeline  safety agencies we surveyed reported using at least one of five practices  that were most frequently cited to help ensure the safety of federally  unregulated pipelines. However, we also found that the sharing of  information among states on the safety practices used appeared to be  limited, and that some state and PHMSA officials we interviewed had  limited awareness of safety practices used by other states. We  recommended that PHMSA establish an online clearinghouse or other  resource for sharing information on pipeline safety practices. In response,  PHMSA requested that the National Association of Pipeline Safety  Representatives develop an online resource document library for states to  obtain and post information related to gathering pipelines. This online  library was established in May 2014 and includes, among other things,  state-specific regulatory information for gathering pipelines, such as rules,  definitions, and inspection form examples.
In our 2014 report, we examined the transportation impacts of increased  oil and gas extraction and found that construction of larger, higher- pressure gathering pipelines had increased to meet the increased oil and  gas production. Such pipelines, if located in rural areas, are generally  not subject to DOT safety regulations that apply to other pipelines. This  includes requirements for emergency response planning that apply to  other pipelines but do not apply to rural unregulated gathering pipelines.  For example, transmission pipeline operators with pipelines similar in size  to the new gathering pipelines are required to develop comprehensive  emergency response plans and coordinate with local emergency  responders. Emergency response officials we spoke with stated that  without information about the location of some gathering pipelines,  responders—particularly in rural areas—may not be adequately prepared  to respond to an incident. Consequently, response planning in rural areas  with federally unregulated gathering pipelines may be inadequate to  address a major incident. Historically, gathering pipelines were smaller  and operated at lower pressure and thus posed less risk than long- distance pipelines. However, state pipeline regulators, PHMSA officials,  and pipeline operators we spoke with said that some newly built gathering  pipelines have larger diameters and higher operating pressures that more  closely resemble transmission pipelines than traditional gathering  pipelines. For example, while gathering pipelines have traditionally been 2  to 12 inches in diameter, one company operating in a Texas shale region  showed us plans to build 30- and 36-inch natural gas gathering pipelines,  which is near the high end of diameters for regulated transmission  pipelines. The recent increase in their size and pressure raises safety  concerns because they could affect a greater area in the event of an  incident. Although states may regulate some gathering pipelines in rural  areas, a 2013 report on state pipeline oversight by an association of state  pipeline regulators showed that most states do not currently regulate  gathering pipelines in rural areas.
PHMSA has been working to propose regulatory changes to address  safety risks of unregulated gathering pipelines, but this effort is not yet  complete. PHMSA issued Advance Notices of Proposed Rulemaking for  onshore hazardous liquid and gas pipelines in October 2010 and August  2011, respectively, seeking comment on whether to require operators to  report on federally unregulated gathering pipelines, as well as on whether  to establish a new, risk-based regime of safety requirements for large- diameter, high-pressure gas gathering pipelines, including those pipelines  in rural locations. PHMSA also noted that enforcement of current  requirements has been hampered by the conflicting and ambiguous  language of the current regulation that can produce multiple  classifications for the same pipeline system, which means that parts of a  single pipeline system can be classified as rural gathering pipelines and  therefore be federally unregulated, while other parts of the same pipeline  with the same characteristics are regulated. In our 2014 report, we  recommended that PHMSA move forward with a Notice of Proposed  Rulemaking to address gathering pipeline safety that addresses the risks  of larger-diameter, higher-pressure federally unregulated gathering  pipelines, including subjecting such pipelines to emergency response  planning requirements that currently do not apply. DOT generally  concurred with the recommendation. In July 2015, PHMSA officials told  us the proposed regulations the agency expects to publish in October  2015 will address this recommendation. Specifically, officials said that the  gas pipeline proposal will extend certain requirements (including  emergency response planning) to previously unregulated gathering  pipelines with a diameter greater than 8 inches. PHMSA officials also said  that in the hazardous liquid pipeline proposal, they are planning on using  the proposed annual report and accident data collection from federally  unregulated hazardous liquid gathering pipelines to develop appropriate  and relevant regulations for certain hazardous liquid gathering pipelines  that are currently unregulated.
section_title: Better Guidance on Use of Automated Valves and a Performance-Based Approach to Incident Response Could Improve Operators’ Response Times
paragraphs: In our January 2013 report on pipeline operator incident response, we  found that numerous variables influence the ability of transmission  pipeline operators to respond to incidents. For example, the accuracy of  a leak detection system, the location of response personnel, the  preparedness of emergency responders, and the use of manual or  automated valves can affect the amount of time it takes for operators to  respond to incidents, which can range from minutes to days. However,  even though the primary advantage of installing automated valves is that  operators can respond quickly to isolate the affected pipeline segment  and reduce the amount of product released, automated valves can have  disadvantages as well. Specifically, accidental closures can lead to loss  of service to customers or even cause a rupture. Because the advantages  and disadvantages of installing an automated valve are closely related to  the specifics of the valve’s location, it is appropriate that operators decide  whether to install automated valves on a case-by-case basis. However,  not all operators we spoke with were aware of existing PHMSA guidance  designed to assist operators in deciding when to use automated valves.  Consequently, we recommended that PHMSA use its existing  information-sharing mechanisms to alert all pipeline operators of  inspection and enforcement guidance that provides additional information  on how to interpret regulations on automated valves. PHMSA officials  said they plan to address this recommendation by highlighting existing  guidance during public presentations and in other forums pipeline  operators attend and through an upcoming rulemaking on rupture  detection and valve rules. PHMSA plans to publish a Notice of Proposed  Rulemaking on this issue in February 2016.
In our January 2013 report, we concluded that PHMSA has an  opportunity to improve incident response times by developing a  performance-based approach for pipeline operators to improve incident  response times. We have also previously concluded that a performance- based approach—including goals and associated performance measures  and targets—can allow those being regulated to determine the most  appropriate way to achieve desired outcomes. While PHMSA has  established a national goal for pipeline operators to respond to incidents  in a “prompt and effective” manner, it has not linked performance  measures or targets to this goal.
Defining performance measures and targets for incident response can be  challenging, but we identified a potential strategy for PHMSA to move  toward a more quantifiable, performance-based approach to improve  incident response based on nationwide incident response data. For  example, PHMSA could evaluate nationwide data to determine response  times for different types of pipeline (based on location, operating  pressure, and pipeline diameter, among other factors). First, though,  PHMSA must improve the data it collects on incident response times.  These data are not reliable both because operators are not required to fill  out certain time-related fields in the reporting form and because operators  told us they interpret these data fields in different ways. Consequently, we  found that some pipeline operators did not consistently report the date  and time for when the incident was identified or for when operator  resources arrived on the site of the incident. Some operators also did not  consistently report whether the incident led to a shutdown of a pipeline or  facility. Reliable data would improve PHMSA’s ability to measure incident  response and assist the agency in exploring the feasibility of developing a  performance-based approach for improving operator response to pipeline  incidents.
We recommended that PHMSA improve the reliability of incident  response data and use these data to evaluate whether to implement a  performance-based framework for incident response times. In July 2015,  PHMSA officials told us they have taken several steps toward addressing  this recommendation, including making changes to its incident reports  and requiring that operators report specific pieces of information  regarding an incident. Additionally, PHMSA officials said that, later this  year, they plan to propose further changes to the report forms to collect  additional data that will allow the agency to better track incident response  times. PHMSA officials also said they plan to develop a more specific  performance-based standard for incident response as part of the  upcoming February 2016 rulemaking.
section_title: Guidance and More Information Needed for Use of Risk-Based Reassessment Intervals
paragraphs: The current statutory requirement for natural gas transmission pipeline  operators to reassess pipeline integrity at least every 7 years provides a  safeguard by allowing operators and regulators to identify and address  problems on a continual basis, but in our June 2013 report, we found that  this requirement is not fully consistent with risk-management practices,  which are the basis for PHMSA’s integrity management program. The  primary advantage of the 7-year reassessment requirement is that it is  more frequent than the intervals found in industry consensus standards,  which specify 10-, 15-, or 20-year intervals depending on the  characteristics of individual pipelines. This conservative approach  provides greater assurance that operators are regularly monitoring their  pipelines to address threats before leaks or ruptures occur. However, this  requirement is not fully consistent with risk-based management practices.  Under a risk-based approach, operators could, for example, use  information to identify, assess, and prioritize risks so that resources may  be allocated to address higher risks first. While operators are currently  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. If  the operator’s risk analysis indicates that reassessments should be done  at intervals shorter than 7 years, the operator is required to do so.
Implementing risk-based reassessment intervals that are longer than 7  years for natural gas transmission pipelines would require a statutory  change and could exacerbate current workload, staffing, and expertise  challenges for operators and regulators. For example, PHMSA officials  told us that allowing longer intervals could require inspectors to spend  more time and resources than they do currently to verify that operators  appropriately assessed risk, and state pipeline safety offices we met with  noted potential concerns with staffing and training to effectively evaluate  risk-based reassessment intervals. Further, some operators told us that  extending reassessment intervals to be longer than 7 years would likely  require additional data analyses beyond those currently required. In our  June 2013 report, we found that operators we met with varied in the  extent to which they calculated reassessment intervals and used the  results of data analyses. Further, we found that guidance to calculate  reassessment intervals was lacking, and as a result, operators may  perform a less rigorous determination of their reassessment intervals. As  a result, some operators could be following the 7-year reassessment  interval when their pipeline should be reassessed more frequently (e.g.  within 5 years). To improve how operators calculate reassessment  intervals, we recommended that PHMSA develop guidance for operators  to use in determining risks and calculating reassessment intervals.  PHMSA officials said the agency has drafted guidance on calculating  reassessment intervals that are shorter than 7 years; this guidance is  currently under internal review and agency officials anticipate that it will  be posted on PHMSA’s website by February 2016.
At the request of a congressional committee, in 2008, PHMSA described  how it would establish and enforce risk-based criteria for extending the 7- year reassessment interval for natural gas transmission pipelines. At that  time, PHMSA proposed retaining the current 7-year reassessment  requirement, but also establishing a process by which operators could  use risk-based reassessment intervals that are longer than 7 years if they  met certain potential criteria, such as demonstrating sound risk analysis.  This process would be similar to that used by PHMSA for hazardous  liquid pipeline reassessment intervals. While we and PHMSA have  supported the concept of risk-based reassessment intervals that are  longer than 7 years, given the breadth of potential challenges with  implementation, more information might help decision-makers better  understand the resource requirements and potential safety implications of  such a change. For example, PHMSA has used pilot programs to collect  such information and study the effects prior to rule changes. To better  identify the resource requirements needed to implement risk-based  reassessment intervals that are longer than 7 years for gas transmission  pipelines, we recommended that PHMSA collect information on the  feasibility of addressing the potential challenges of implementing risk- based reassessment intervals that are longer than 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. PHMSA is studying  the potential to implement risk-based reassessment intervals that are  longer than 7 years for gas transmission pipelines; agency officials plan to  complete this research by March 2016.
Chairman Fischer, Ranking Member Booker, and Members of the  Subcommittee, this completes my prepared statement. I would be  pleased to respond to any questions that you may have at this time.
section_title: GAO Contact and Staff Acknowledgments
paragraphs: If you or your staff have any questions about this testimony, please  contact Susan A. Fleming, Director, Physical Infrastructure Issues, 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 statement. GAO staff who made key contributions to this testimony  are Sara Vermillion (Assistant Director), Melissa Bodeau, Matthew Cook,  Juan Garcia, David Hooper, Andrew Huddleston, SaraAnn Moessbauer,  and Daniel Paepke.
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