Pipeline Safety: Additional Actions Could Improve Federal Use of Data on Pipeline Materials and Corrosion
Published: 2017-08-03T00:00:00

Fast Facts:

Highlights:
section_title: Why GAO Did This Study
paragraphs: The U.S. energy pipeline network is composed of over 2.7-million miles of pipelines transporting gas and hazardous liquids. While pipelines are a relatively safe mode of transportation, incidents caused by material failures and corrosion may result in fatalities and environmental damage. PHMSA, an agency within the Department of Transportation, inspects pipeline operators and oversees safety regulations.
2016 pipeline safety legislation included a provision for GAO to examine a variety of topics related to pipeline materials and corrosion. This report addresses: (1) the materials and corrosion-prevention technologies used in the pipeline network and their benefits and limitations and (2) how PHMSA uses data on pipelines and corrosion to inform inspection priorities, among other topics. GAO analyzed PHMSA's 2010–2016 data; reviewed PHMSA regulations; and interviewed PHMSA officials and representatives of nine states selected based on pipeline inspection roles, eight pipeline operators—providing a range of sizes, geographic locations, and other factors—and eight stakeholders selected for expertise on pipeline and corrosion issues.
section_title: What GAO Found
paragraphs: The U.S. gas and hazardous liquid pipeline network is constructed primarily of steel and plastic pipes, both of which offer benefits and limitations that present trade-offs to pipeline operators, as do corrosion prevention technology options. According to data from the Pipeline and Hazardous Materials Safety Administration (PHMSA), over 98 percent of federally regulated pipelines that gather natural gas and other gases and hazardous liquid products, such as oil, and transmit those products across long distances are made of steel. An increasing majority of pipelines that distribute natural gas to homes and businesses are made of plastics. Steel pipelines are manufactured in various grades to accommodate higher operating pressures, but require corrosion protection and cost more than plastics, according to operators and experts. In contrast, plastics and emerging composite materials generally are corrosion-resistant, but lack the strength to accommodate high-operating pressures. Operators use a range of technologies to protect steel pipes from corrosion, including applying coatings and cathodic protection, which applies an electrical current to the pipe. (See fig.) While such technologies are generally considered effective, operators and experts stated that coatings degrade over time and that cathodic protection requires ongoing maintenance and costs to deliver the current over long pipeline distances, among other considerations.
PHMSA uses materials and corrosion data collected from operators in its Risk Ranking Index Model to determine the frequency of PHMSA's inspections of operators based on threats, such as ineffective coatings, to pipeline integrity. PHMSA officials said they used professional judgment to develop their model, but did not document key decisions for: (1) the threat factors selected, (2) their associated weights, or (3) the thresholds for high, medium, and low risk tiers for pipeline segments inspected by PHMSA. Moreover, PHMSA has not used data to assess its model's overall effectiveness, as would be consistent with federal management principles. PHMSA officials said they have not established an evaluation process because they consider the model to be effective in prioritizing inspections. Although PHMSA officials said they analyzed the model when they developed it in 2012, they have not done so since that time and did not document the results of this initial analysis. Without documentation and a data-driven evaluation process, PHMSA cannot demonstrate the effectiveness of the model it uses to allocate PHMSA's limited inspection resources.
section_title: What GAO Recommends
paragraphs: GAO recommends that PHMSA document the design of its Risk Ranking Index Model and implement a process that uses data to periodically assess the model's effectiveness. The Department of Transportation agreed with our recommendation and provided technical comments, which we incorporated as appropriate.

section_title: Letter
paragraphs: The U.S. energy pipeline network is composed of over 2.7-million miles of  pipeline transporting gas, oil, and other hazardous liquids across the  country. This network is owned, operated, and maintained by about  3,000 pipeline operators; the Department of Transportation’s Pipeline and  Hazardous Materials Safety Administration (PHMSA) is responsible for  overseeing the network’s safety. Pipelines are relatively safe when  compared with other transportation modes, such as rail and truck, though  when pipeline incidents do occur they can result in fatalities and  environmental damage. While pipeline incidents may be caused by a  variety of factors, from 2010 through 2015, pipeline material and weld  failures and corrosion were the reported cause of about one-third of  significant pipeline incidents across the pipeline network, according to  data collected by PHMSA. For example, according to the National  Transportation Safety Board (NTSB), external corrosion and the failure to  detect that corrosion were the probable causes of a 2012 natural gas  transmission pipeline rupture in Sissonville, West Virginia. The rupture  destroyed and damaged several houses, and released and burned nearly  76-million cubic feet of natural gas. This incident and others have raised  questions about the materials used to construct pipelines and associated  corrosion prevention technologies, the training and experience of the  personnel that prevent and manage corrosion, and how PHMSA uses  data on corrosion and materials to oversee pipeline safety.
The Protecting our Infrastructure of Pipelines and Enhancing Safety Act  of 2016 included a provision for us to report on a variety of topics related  to pipeline materials, training, and corrosion prevention technologies for  gas and hazardous liquid pipelines. This report discusses:  1.  the pipeline materials and corrosion prevention technologies that are  used in the gas and hazardous liquid pipeline network and their  respective benefits and limitations;  2.  how selected pipeline operators train personnel to manage corrosion  and the challenges that exist in ensuring personnel are qualified; and  3.  how PHMSA uses data on pipelines and corrosion prevention to  inform its inspection priorities.
This report also includes information on the use of pipeline materials and  corrosion prevention technologies outside the United States as well as  potential future improvements in materials and corrosion prevention  technologies. (See app. I.)
For each of these objectives, we reviewed pertinent PHMSA regulations  and documents and interviewed PHMSA headquarters officials. To  determine what pipeline materials and corrosion prevention technologies  are used in the gas and hazardous liquid networks, we analyzed the most  recent full-year data (calendar years 2010–2015) on pipeline  characteristics and corrosion prevention technologies reported to PHMSA  by pipeline operators. To assess the benefits and limitations of these  materials and technologies, we reviewed Department of Transportation  reports and academic literature, and interviewed a nongeneralizable  sample of eight pipeline operators and eight stakeholders with expertise  on pipeline materials and corrosion (expert stakeholders). These pipeline  operators represent a range of pipeline functions, types of materials  transported, the network size (miles of pipeline), geography, and  recommendations from other stakeholders. We selected expert  stakeholders based on their knowledge of pipeline materials and  corrosion as determined by their employment or experience, and  recommendations of other expert stakeholders. The views provided by  pipeline operators and expert stakeholders cannot be generalized to all  pipeline operators and experts, but do provide perspectives on the  benefits, limitations, costs and other aspects of the pipeline materials and  corrosion prevention technologies discussed in these interviews.
To analyze how selected pipeline operators train personnel to manage  corrosion, we reviewed PHMSA regulations and proposed changes to those regulations requiring that pipeline operator personnel are qualified  for operational and maintenance tasks, including corrosion prevention  activities. We reviewed pipeline operator training plans and other  documentation. We interviewed 17 stakeholders, including staff from the  eight selected pipeline operators, as well as staff from three unions, three  training providers and three industry associations. These interviews  provided a range of views on approaches, common practices, and  challenges associated with corrosion training and are not generalizable  across all industry stakeholders.
To determine how PHMSA uses data on materials and corrosion  prevention to inform its inspection priorities, we analyzed and assessed  the reliability of the most recent PHMSA inspection and enforcement data  (calendar years 2014–2016) that contained information related to  pipelines and corrosion prevention. We evaluated PHMSA’s use of these  data in its risk-ranking index model that PHMSA uses to rank the relative  risk of pipelines and prioritize its annual inspections of pipeline operators.  We compared this approach to criteria identified in GAO’s Standards for  Internal Controls in the Federal Government’s criteria for risk analysis  developed by the Office of Management and Budget (OMB) and  PHMSA’s strategic objectives. To understand how inspection data are  collected and used to inform PHSMA’s oversight, we interviewed staff  from each of PHMSA’s five regional offices, which are responsible for  conducting inspections of pipeline operator operations. We also  conducted a group discussion with officials from all nine states that have  been designated as “interstate agents” to assist PHMSA in inspecting  interstate pipelines. To assess the reliability of the data used in our  review, we examined PHMSA reports, analyzed the data to identify any  outlier values, and interviewed PHMSA officials about how the data were  collected, stored, and validated, among other things. We determined that  the data were sufficiently reliable for the purposes of our reporting  objectives. Additional information on our objectives, scope, and  methodology is included in appendix II.
We conducted this performance audit from July 2016 to August 2017 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: More than 2.7-million miles of pipeline transport roughly two-thirds of our  nation’s domestic energy supply. These pipelines carry gas and  hazardous liquids from producing wells, to processing plants, and  eventually to end users, such as businesses and homes. (See fig. 1.)  Within this nationwide system, there are three main types of pipelines— gathering, transmission, and distribution. Based on annual reports  submitted to PHMSA by pipeline operators at the end of 2015, there were  about 18,000 miles of gas gathering pipelines, 301,000 miles of gas  transmission pipelines, and 2.2 million miles of gas distribution pipelines  regulated by PHMSA. In addition, in 2015 there were about 4,000 miles of  liquid gathering pipelines and 205,000 miles of hazardous liquid  transmission pipelines regulated by PHMSA.
Gathering pipelines: Gas gathering pipelines collect natural gas and  other gases from production areas, while hazardous liquid gathering  pipelines collect oil and other petroleum products from oil well heads.  Gathering pipelines operate at pressures ranging from about 5 to 800  pounds per square inch (psi). These pipelines then typically transport  the products to processing facilities, which in turn refine the products  and send them to transmission pipelines.
Transmission pipelines: Transmission pipelines carry gas or  hazardous liquids, sometimes over hundreds of miles, to communities  and large-volume users (e.g., factories). Transmission pipelines  tend to have the largest pressures of the three types of pipelines,  generally operating at pressures ranging from 400 to 1,440 psi.
Gas distribution pipelines: Gas distribution pipelines transport natural  and other gas products to residential, commercial, and industrial  customers. These pipelines tend to operate at lower pressures—0.25  to 100 psi.
As noted earlier, pipeline material and weld failures and corrosion  together are among the leading causes of significant incidents from 2010  through 2015, as reported to PHMSA by pipeline operators. (See fig. 2.)  Material failures can occur due to impurities in the steel manufacturing  process, defects in the manufacturing process to convert steel into  pipelines, or from failures in the welding or joining of pipeline segments  together, among other causes. Corrosion can occur on the exterior or  interior of a metallic pipeline, during which electrons from the metal  undergo electrochemical reactions often involving water or oxygen,  resulting in the degradation of the pipeline. External corrosion may result  when the metal surface of the pipe is exposed to groundwater or soil  environments that increase electrical conductivity of a pipeline and  accelerate the corrosion process. External corrosion is also a factor in  stress corrosion cracking, where stress on the pipeline from high or  fluctuating operating pressures and corrosive environmental conditions  cause cracks to form in pipeline material. Internal corrosion occurs inside  the pipeline, and may be caused by the presence of water, corrosive  materials, or bacteria.
PHMSA has established regulations that identify requirements for pipeline  materials and corrosion prevention technologies in the gas and  hazardous liquid pipeline network. PHMSA’s regulations identify design  standards for pipelines and regulate what materials can be used under  different operating conditions and pressures. For corrosion prevention,  external coatings and a technology known as cathodic protection are  required for metallic pipes installed beginning in 1971. External coatings  are a protective layer of plastic material or other chemical compounds  applied and bonded across the metallic surface of a pipe. Coatings are  applied prior to or during installation, and coat both the pipe and the  welds that join pipeline segments together. However, external coatings  can be damaged by construction or degrade over time. Therefore, after  the external coatings are applied, cathodic protection is added. Cathodic  protection involves applying an electrical current onto the pipeline to  control external corrosion. External coatings and cathodic protection  thus work together to protect the pipeline by disrupting the chemical  process that leads to corrosion. (See fig. 3.)
Under PHMSA’s pipeline safety program, pipeline operators take primary  responsibility for the integrity of their pipelines, and PHMSA conducts  inspections to ensure operator compliance with federal safety regulations.  For example, the Pipeline Safety Improvement Act of 2002 required  PHMSA to implement a risk-based approach to gas and hazardous liquid  transmission pipeline safety, an approach known as integrity  management. The integrity management program requires operators to,  among other things, systematically identify threats and mitigate risks to  pipeline segments located in high consequence areas, which include  highly populated or environmentally sensitive areas. PHMSA and state  pipeline safety offices conduct inspections to oversee operators’  compliance with this and other federal requirements.
PHMSA has also established regulations requiring operators to ensure  that personnel are qualified to perform certain tasks, including corrosion  control activities such as monitoring cathodic protection. In its operator  qualification regulations, PHMSA has stated its objective is to reduce the  risk of accidents on pipelines attributable to human error. These  regulations require that operators develop a written qualification plan that  identifies a list of covered tasks for personnel as well as an approach to evaluate whether individuals are qualified to perform those tasks. (See  table 1.) Operator qualification plans may include provisions to provide  training, as appropriate, to ensure that individuals performing covered  tasks have the necessary knowledge and skills to perform the tasks in a  manner that ensures safe operation. The regulations do not prescribe  how operators must evaluate personnel to ensure they are qualified,  though they state the evaluation may take the form of a written or oral  exam, on-the-job performance assessment, or a simulation, among other  methods.
PHMSA and state pipeline safety offices work together to oversee and  inspect federally regulated gas and hazardous liquid pipelines. In general,  PHMSA has primary authority to regulate and enforce interstate pipeline  safety, including the design, construction, operation and maintenance of  pipelines certified by the Federal Energy Regulatory Commission or  crossing state lines. In the nine states designated as interstate agents,  state pipeline inspection staff supplements PHMSA inspections, but  PHMSA maintains enforcement authority over these pipelines. Regarding  intrastate pipelines, state pipeline safety offices may assume inspection  and enforcement responsibility for intrastate pipelines in their states after  annually certifying to PHMSA that they are complying with applicable  federal standards for their oversight. PHMSA currently has certifications  with the 48 contiguous states, the District of Columbia, and Puerto Rico  for intrastate gas pipelines within their boundaries, and with 15 states for  hazardous liquid intrastate pipelines. If a state authority does not apply for  annual certification, inspection, and enforcement activities, all intrastate  facilities in that state remain the responsibility of PHMSA.
PHMSA’s pipeline inspectors and the nine interstate agents conduct  periodic integrated inspections of interstate pipelines. These inspections  look at the entirety of an operator’s pipeline safety approach, including  ensuring operators meet operator qualification requirements. PHMSA  conducts its integrated inspections on individual pipeline segments,  known as inspection systems. These inspection systems are comprised  of one or more smaller pipeline units. PHMSA’s Office of Pipeline Safety  employs over 200 staff across headquarters and 5 regional offices, with  about 130 of those staff involved in inspections and enforcement of  interstate pipelines.
As part of oversight activities, PHMSA also collects a range of data on  pipeline materials and corrosion prevention through annual operator  reporting and incident reports, and during its integrated inspections. The  data describe various characteristics of the pipeline, including the type of  material (e.g., steel, plastic, or composite), the diameter of the pipe, and  when it was installed. The corrosion prevention data include information  on whether the pipeline is coated and cathodically protected, and other  characteristics associated with corrosion.
section_title: Pipeline Operators Use Steel, Plastics, and Various Corrosion Prevention Technologies, Which Have a Range of Benefits and Limitations
subsections: section_title: Nearly All Federally Regulated Pipelines Are Constructed of Steel or Plastic, Which Involve Various Benefits, Limitations and Costs
paragraphs: The vast majority (over 95 percent) of U.S. gas and hazardous liquid  pipeline miles that PHMSA regulates are constructed of either steel or  plastic, with relatively minor use (less than 5 percent) of other materials,  including composites and iron, according to our analysis of PHMSA data  from 2015. (See table 2.) The extent of steel and plastic use varies in  different parts of the pipeline network (gathering, transmission, and  distribution) due to operating conditions and other factors, as discussed  below. For example, nearly all pipeline miles in the transmission network  consist of steel pipelines, while plastic pipelines represent over half of  pipeline miles in the gas distribution network. In addition, the ratio of  these materials within the network has changed over time. PHMSA’s data  indicates that, from 2010 through 2015, the percentage of plastic pipeline  miles in the gas distribution network increased from 58 to 62 percent.  According to industry stakeholders we interviewed, the vast majority of  new and replacement distribution pipes are made of plastics.
The composition and use of these materials can vary widely:
Steel: Steel is widely used in the gathering, transmission, and  distribution segments of the pipeline network, and can be  manufactured in various grades (strengths). Each grade refers to a  specific strength range and chemical composition of iron and a small  percentage of various elements, including carbon and manganese.  According to operators and expert stakeholders we interviewed, the  grade of steel used in a pipeline depends on a variety of factors,  including the required operating pressure to propel the product  through the pipeline, the operating environment, and cost. PHMSA  regulations establish a design formula to determine the maximum  allowable operating pressures for pipelines constructed from various  grades of steel. In practice, steel’s strength to withstand high  operating pressures and other design characteristics generally  facilitate its use across all portions of the pipeline network. Corrosion- resistant steel alloys, such as stainless steel, are used in limited  circumstances due to their high costs, according to a few operators  and expert stakeholders. Such alloys are used primarily in offshore  applications or in limited circumstances to gather particularly corrosive  oil or gas products or in high consequence areas.
Plastic: Plastics are used primarily in gas distribution pipelines, along  with a smaller percentage of gathering pipelines. Specifically,  operators and expert stakeholders identified polyethylene, which is a  plastic used to make many common household products such as  bottles and food wrap, as the most commonly used plastic, particularly  within the gas distribution network. According to PHMSA data, 99  percent of plastic pipeline distribution network miles are composed of  polyethylene. An operator and industry stakeholder also identified  polyamides, a nylon-woven plastic, as an emerging pipeline material  due to its increased strength, although it is currently only used in less  than 1 percent of distribution pipeline miles according to PHMSA data.  Current PHMSA regulations permit plastic pipelines to be used at  pressures up to 100 psi, with exceptions for certain polyethylene  pipelines that can be used up to 125 psi, and certain polyamides up to  200 psi. In 2015, PHMSA proposed changes to these regulations  that would allow use of polyamide plastic pipelines at even higher  operating pressures.
Composites: Although composites, such as fiberglass, fiber-reinforced  plastic, and other materials represent a very small portion of the  nation’s pipeline network miles, two expert stakeholders reported  increasing use of the these materials primarily in gathering. For  example, one expert stakeholder said that fiber pipe was starting to be  adopted in place of steel for gathering in certain situations because it  can be used at higher pressures than polyethylene. Operators and  expert stakeholders also told us that composite pipes are generally  corrosion-resistant and are easier to transport and install, as they may  come in spoolable reels and do not require welding. However,  PHMSA officials noted that the design and materials for composite  pipelines can vary substantially, and there are few applicable  standards or requirements for composite materials. Consequently,  composite materials need to be vetted individually for each specific  use, according to PHMSA. As a result, PHMSA requires operators to  obtain special permits to use composite materials, and the maximum  allowable operating pressure can vary depending on the type of  material proposed. From 2010 through March 2017, PHMSA had  approved 8 of 14 special permit applications that proposed the use of  composite materials in the pipeline network. PHMSA officials stated  that the pipeline industry is working to develop standards for these  materials, and the industry has petitioned PHMSA to incorporate any  such standards into its regulations.
Operators and expert stakeholders identified a variety of benefits and  limitations associated with commonly used pipeline materials, such as the  ability or inability to accommodate high pressures, and resistance or  susceptibility to corrosion. More specifically, for steel, plastic, and  composite pipelines, they identified trade-offs among these materials, as  detailed in table 3. For example, while steel provides strength and can  accommodate higher operating pressures compared to plastic and  composites, it is susceptible to corrosion and requires the use of  corrosion protection technologies. In contrast, plastic and composite  materials are generally corrosion-resistant, except when metallic  components are used in some composite pipes that are reinforced with  steel. However, NTSB officials noted that assessing the integrity  management of plastic pipelines can be challenging because there are  limitations in established technologies currently available to assess flaws  in plastic pipe or certain joints, and the industry has limited data regarding  the long-term reliability of plastic pipelines and associated components.
Although several operators and expert stakeholders told us that steel  generally costs more per unit than plastic, the relative costs of pipelines  made of these materials depend on an interplay of factors, including  pipeline design, installation, and maintenance.
Design: According to almost all the operators and expert stakeholders  we interviewed, the design of a pipeline, including the intended  operating pressure, is a significant factor in the selection of a pipeline  material, and a majority of operators and expert stakeholders we  interviewed said that pipeline diameter and wall thickness can affect  the cost of pipeline materials. Specifically, at lower diameters and  pressures, such as in distribution and some gathering pipelines,  plastic often has a cost advantage, while in the larger diameters and  pressures of transmission pipelines, steel is the only cost-effective  material. Higher diameters and pressures necessitate increasingly  thicker walls, which makes plastic cost prohibitive, according to  operators and expert stakeholders. Steel, in contrast, can be  manufactured at higher grades, allowing thinner but stronger walls, or  at lower grades producing thicker, but lower-strength walls. Operators  and experts told us that because pipeline steel is purchased by  weight, the pipeline industry has increased its use of higher grade,  thinner-wall steel in recent years to reduce material costs while  maintaining higher strengths.
Installation: Operators and expert stakeholders we interviewed told us  that installation is a major cost component for pipelines, though these  costs are generally higher for steel than other materials. Generally, in  circumstances where either steel or plastic could be used, operators  and expert stakeholders told us that installation of steel is more  expensive than plastic. For example, a steel pipeline requires that a  trench be dug and prepared before installation, while plastic can often  be plowed into the ground without preparation, reducing time and  expense. Joining of pipe sections, by either welding (steel) or fusing  (plastic) is an important component of installation and can also add to  the cost. Operators and expert stakeholders also told us that welding  steel is more difficult and time consuming than fusing plastic, adding  to the cost. Operators and expert stakeholders also noted that  composite material pipeline segments can be challenging to join with  other segments in the pipeline network.
Maintenance: For steel pipelines, over half of the operators and expert  stakeholders we interviewed stated that material-specific maintenance  costs to prevent corrosion can affect the overall life-cycle cost of the  pipeline. For example, several operators and expert stakeholders said  that while using higher grade steel allows operators to reduce overall  steel material expense, higher grade steel pipelines have thinner walls  and may have less corrosion allowance—that is, the amount of  material that may corrode without affecting the integrity of the pipeline.  As such, higher grade steels can result in higher maintenance costs  associated with monitoring and corrosion prevention, according to one  expert stakeholder. Operators and expert stakeholders noted that  while plastic pipelines do not have corrosion prevention maintenance  costs, they are more susceptible than steel to third-party damage that  requires repair.
section_title: Most Federally Regulated Pipelines Use Corrosion Prevention Technologies, Which Involve Various Benefits, Limitations, and Costs
subsections: section_title: External Corrosion Prevention Technologies
paragraphs: Operators and expert stakeholders we interviewed stated that the primary  technologies to prevent external corrosion are coatings and cathodic  protection, and these tools are widely used across the pipeline network.  As previously noted, PHMSA regulations require external coatings and  cathodic protection for all metallic pipes installed beginning in 1971.  According to our analysis of PHMSA operator-submitted data, operators  have externally coated and cathodically protected over 96 percent of steel  gathering and transmission pipelines and 85 percent of steel distribution  pipelines across the federally regulated pipeline network. A lower  percentage of steel distribution pipelines are externally coated and  cathodically protected because distribution networks in many areas were  installed before 1971. According to PHMSA officials, these older,  unprotected steel distribution pipelines are often replaced with plastic,  which reduces the total mileage of unprotected steel distribution pipelines.
Coatings and cathodic protection offer important safety benefits to protect  steel pipelines from external corrosion, but these technologies also have  limitations in their effectiveness. Operators and expert stakeholders  generally agreed that coatings and cathodic protection are  complementary technologies and function most effectively when used  together. Specifically, coatings provide a protective barrier to the  pipeline surface, and if this barrier is compromised, cathodic protection  delivers an electric current to the exposed area to inhibit corrosion. In  addition, over half of the operators and expert stakeholders we  interviewed stated that these technologies are also used to prevent stress  corrosion cracking in steel pipelines. However, these technologies have  some limitations. For example, according to operators and expert  stakeholders, some coatings can be difficult to install and apply in the  field and all coatings can deteriorate over time. They also said that a  variety of different coatings exist and their effectiveness can vary based  on operating factors, particularly in extreme temperatures which can  disbond coatings from the pipe surface. Operators and expert  stakeholders also told us that the effectiveness of cathodic protection can  be limited by “shielding,” which occurs when the electrical current is  obstructed from reaching the pipeline by obstacles such as rocks, failed  coatings, or interference from nearby electric power cables. (See table  4.)
Operators and expert stakeholders we interviewed identified a variety of  factors that can affect the cost of these technologies. According to  operators and expert stakeholders, coatings and cathodic protection are  generally a cost-effective way to protect steel pipelines against external  corrosion and stress corrosion cracking, and operators and expert  stakeholders said that coatings and cathodic protection are a relatively  small portion of total pipeline cost. According to operators and expert stakeholders, factors that can affect the overall cost of coatings include  the type of coating; application costs, including application of coating to  pipeline joints in the field after welding; and maintenance of the coating  (which requires excavation, inspection, and repair). Factors that can  affect the overall cost of cathodic protection include initial installation of  equipment; the cost of providing power, including in remote locations  where power is not readily available; the need to increase electrical power  over time to protect the pipeline as coatings degrade; and on-going  monitoring and maintenance.
section_title: Internal Corrosion Prevention Technologies
paragraphs: Operators and expert stakeholders also identified internal corrosion  prevention technologies along with their benefits and limitations. (See  table 5.) According to PHMSA, many interrelated technical factors can  affect the likelihood, aggressiveness, and location of internal corrosion.  For example, certain types of internal corrosion are caused by chemical  reactions between the material being transported and the wall of the  pipeline. In these cases, pipeline operators stated that they typically inject  “inhibitors”–chemical compounds that inhibit these chemical reactions.  The type of chemical compound injected will depend on the type of  product, cost, availability, and environmental effect. In other cases,  pipeline operators stated that they can use devices known as “cleaning  pigs.” Cleaning pigs are electronic devices with cleaning brushes  attached to them that run through the inside of the pipeline to scrub it and  remove water and other contaminants from the pipeline. Operators and  expert stakeholders also emphasized the importance of controlling  pipeline-operating conditions to prevent internal corrosion, including  maintaining sufficient flow and velocity of products in the pipeline to  reduce the accumulation of water and contaminants.
A variety of factors affect the cost of internal corrosion prevention  technologies. First, operators and expert stakeholders noted that labor  and equipment, such as installing infrastructure to launch and receive the  cleaning pigs, can be expensive. Second, operators and expert  stakeholders noted that the use of cleaning pigs can temporarily reduce  the flow rate of the product so, while not necessarily affecting costs, the  revenue of the pipeline operator could be affected by the use of the  technology. Third, the extent of the internal corrosion threat can require  greater use of inhibitors and cleaning pigs, thereby increasing the costs  for the pipeline operator. Similar to coatings and cathodic protection, only  two of the operators and expert stakeholders we interviewed provided  specific information on the costs of these technologies, and generally  noted that the costs of these technologies vary with the type of  technology used.
section_title: Selected Pipeline Operators Reported Using a Variety of Sources for Pipeline Corrosion Training and Identified Challenges Ensuring Personnel Are Qualified Pipeline Operators and Unions Use Internal and Third-Party Corrosion Training for Personnel
paragraphs: Gas and hazardous liquid pipeline operators use several sources to train  personnel on pipeline corrosion, including in-house training and third- party programs, according to our interviews with eight operators and nine  other stakeholders, including unions, training providers, and industry  associations. According to operator qualification regulations from  PHMSA, operators have discretion to determine the training approaches  they provide to ensure personnel are qualified. Operators are also  responsible under the regulations for ensuring any contractor personnel  they hire for operations and maintenance tasks are qualified, even if the  contractors are already trained for those tasks. The operators we  interviewed told us that PHMSA’s operator qualification regulations  provide flexibility to tailor their operator qualification program and any  corresponding training program to their operational needs. In practice,  operators and stakeholders told us this flexibility allows operators to use  several training sources and approaches to supplement their operator  qualification plans.
Internal training programs: Operators and stakeholders noted internal  training programs vary across companies, depending on factors such  as the type of pipeline, environment, and staff resources. All of the  eight operators we spoke with provided in-house training programs  depending on the needs of the company. Six of the eight operators  said their in-house training included methods such as on-the-job  training, mentoring programs, apprenticeships, and online training.  Such training programs teach skills related to corrosion prevention  such as applying pipe coating, conducting cathodic protection  surveys, and examining the soil surrounding the pipe. Operators we  interviewed also identified different approaches for retraining staff to  maintain qualification. For example, one hazardous liquid operator  requires all corrosion technicians and contractors to take training and  assessments every 3 years, while another hazardous liquid operator  stated that it assigns retraining intervals from 2 to 6 years based on  the risk associated with each task.
Third-party training providers: In addition to internal training, operators  also frequently use third-party training providers, according to  operators and stakeholders we interviewed. All eight operators and six  stakeholders said operators typically use third-party providers, such  as industry associations and colleges, for general corrosion training  programs. For example, NACE International, formerly the National  Association of Corrosion Engineers (NACE), offers two training  programs on corrosion prevention technologies: a series of courses  on pipeline coatings and a series of courses on cathodic protection.  All eight operators said they use NACE training, and six operators  said they consider NACE certifications to be the industry standard for  hiring corrosion personnel. Several operators also reported that their  personnel attended the Appalachian Underground Short Course,  which offers a variety of corrosion-related courses at four levels of  difficulty, along with a separate course on pipeline coatings. Operators  also cited Purdue University’s Corrosion College and the Midwest  Energy Association’s EnergyU as frequently used sources of  corrosion training.
Industry association guidance: Operators also make use of industry  associations’ guidance for training, according to one operator and  three stakeholders. For example, operators may consult practices  from the American Society of Mechanical Engineers, which offers  guidance on training programs and identifies 170 tasks personnel  should be able to perform, including corrosion-related tasks.  Operators also use recommended practices from the American  Petroleum Institute, including guidance that identifies 99 pipeline  operational safety tasks, such as corrosion-related tasks.
Union training for members: Unions are another source of pipeline  corrosion training. Two of the three unions we spoke with provide  pipeline training to their members related to corrosion prevention. For  example, one union representing contractors uses a third party to  provide training for its members on pipelines using its national training  fund. The course does not specifically cover corrosion but addresses  pipe damage and abnormal operating conditions such as corrosion.  Staff from a second union that represents contractors said that they  train members to their own national standards for specific corrosion- related tasks, such as those related to pipeline coating and cathodic  protection. The staff stated that personnel must have completed the  union’s pipeline technical course to be dispatched to job sites.  However, operators must separately ensure the personnel are  qualified to perform the specific tasks they are contracted to complete,  as discussed below. A third union, which represents operator  employees, said that while the union does not provide formal training,  its members receive training from the operators.
subsections: section_title: Stakeholders Stated PHMSA’s Operator Qualification Requirements May Present Challenges for Pipeline Operators, Contractors, and PHMSA
paragraphs: Although PHMSA’s operator qualification regulations allow operators  flexibility in training approaches, operators and contractors identified  several challenges. In particular, operators told us that they rely on  contractors for a variety of corrosion-related tasks, in part because of  limited resources, and a need for specialized expertise. Because  approaches to training and operator qualification vary across the industry,  operators have difficulty verifying contractor qualification, and contractor  training and qualification may not transfer to various operators.
Operator challenges: Operators and stakeholders identified  challenges in ensuring that contractor personnel have the skills and  abilities to carry out various corrosion-related tasks associated with  PHMSA’s operator qualification regulations, known as covered tasks.  Although, according to the regulations, operators are responsible for  ensuring their contractors are qualified, seven of the eight operators  we spoke with said verifying contractor qualifications was challenging.  For example, an operator we interviewed said even if a contractor has  completed a training program from a union or third-party provider, the  contractor may not be trained or have the experience to fulfill the  operator’s needs and the operator may need to separately evaluate  the contractor’s ability to perform covered tasks. In addition, three  operators and two unions said qualification evaluations do not always  accurately reflect contractors’ skills and abilities. For example, one  operator said contractor personnel may have passed an evaluation to  install cathodic protection, but they may not have been trained to  complete important parts of the installation, such as the use of  specialized tools to measure electrical current.
Contractor challenges. Operators and stakeholders also said  contractors’ training and qualifications are not always transferrable,  though perspectives on the severity of the challenge and approaches  to address it varied. Three operators and one union stated that an  evaluation is not always portable to different companies, which one  union said can be a barrier for contractors to obtaining work. For  example, one operator said it requires contractors to undergo training  and evaluations from specific, third-party providers to demonstrate  they are qualified to perform 31 specific covered tasks related to  corrosion prevention in their operator qualification plan and noted that  the operator does not accept contractors with qualifications from other  providers. Furthermore, three operators we interviewed noted that  even if contractors have been previously evaluated by the operator,  they may need to be retested for each covered task by the same  operator or by a third-party accepted by the operator.
The two unions representing contractors we spoke with had different  perspectives on the portability of evaluations and related training. One  union representing contractors said lack of portability was a challenge for  its members, who may have to take duplicative training and might lose  income while completing an evaluation before starting a job. Another  union representing contractors said that while each operator usually  prefers its own internal training methods, portability was not a significant  issue for its members.
Operators and other stakeholders we spoke with identified mechanisms  under way to address these challenges. Six pipeline operators told us  they currently rely on third-party companies to facilitate the verification  and portability of qualifications in the pipeline industry. For example, one  training vendor stated that it maintains an operator qualification program  for over 140 pipeline operators across the country. This vendor said it  customizes covered tasks’ lists based on each client’s needs, though  some tasks are common, such as those related to coating and cathodic  protection. The vendor said operators may hire it to conduct on-site  evaluations to qualify personnel and train operator staff to conduct  evaluations. Stakeholders and operators also identified broader solutions  to overcome these challenges across multiple operators. For example,  one industry organization representing hazardous liquid pipeline  operators said there is currently an industry initiative examining  challenges related to the portability of training.
In addition to the above challenges operators and stakeholders cited,  PHMSA has taken steps to update its regulations related to corrosion  prevention training. In July 2015, PHMSA proposed changes to its  regulations through the rulemaking process to provide additional direction  on pipeline training and operator qualification. More specifically, PHMSA  proposed to clarify topics unaddressed in the initial version of these  regulations published in 1999.
First, as noted above, PHMSA’s regulations identify training as one  option to ensure personnel qualification, but operators have discretion  to determine the extent of training to provide. The proposed changes  to PHMSA’s existing operator qualification regulations would, among  other things, require operators to provide training for personnel who  perform operator-defined covered tasks, though operators would have  discretion in determining what training to provide for employees and  contractors covered by the regulations.
Second, PHMSA has noted that since the current regulations are not  prescriptive, the resulting flexibility makes it difficult to measure an  operator’s compliance with the rule. Moreover, PHMSA officials said  that operators do not always review their covered tasks, evaluations,  and procedures to ensure they are effective. The proposed changes  would require pipeline operators to evaluate the effectiveness of their  operator qualification program and retain records of these evaluations.
Third, the current operator qualification regulations cover activities on  pipelines after they are installed, but there are no requirements to  cover new construction tasks. As a result, operators are not required  to ensure that personnel employed or contracted to construct new  pipelines meet specific qualifications to perform construction tasks.  The proposed changes would expand the scope of the operator  qualification regulations to cover new pipeline construction and other  currently uncovered tasks.
PHMSA issued a final rule in January 2017 addressing other pipeline  safety issues considered in the 2015 proposed changes, but it did not  issue a decision on the proposals related to the above topics.  Specifically, as part of the final rule, PHMSA noted that it expects to  publish an additional final rule on operator qualifications in the near  future, after it considers and evaluates comments received from  stakeholders.
section_title: PHMSA Uses Data on Pipelines and Corrosion Prevention to Prioritize Inspections, but Lacks a Process to Assess and Validate the Effectiveness of Its Approach
paragraphs: PHMSA uses data on pipelines and corrosion collected from operators in  its Risk Ranking Index Model (referred to as RRIM) to determine the  frequency of PHMSA’s inspections of operators based on threats to  pipeline integrity, such as ineffective coatings. In recent years, PHMSA  has taken steps to improve the quality of the data used in RRIM, including  reviewing operator-reported data for outlier values. PHMSA officials  designed RRIM using their professional judgments, and they did not  document the rationale or justification for key decisions, including the  selection of threat factors and their associated weights. Moreover,  PHMSA has not used data to assess the model’s overall effectiveness  and lacks a process to do such an evaluation. Without documentation and  a data-driven evaluation process, both of which are consistent with  federal management principles, PHMSA cannot demonstrate the  effectiveness of RRIM in allocating PHMSA’s limited inspection resources  according to pipeline threats or targeting its limited resources to the  greatest threats.
subsections: section_title: PHMSA Uses Data on Pipelines and Corrosion Prevention to Prioritize Inspections
paragraphs: Since 2011, PHMSA has used data on pipelines and corrosion  prevention, along with other data elements, in a risk ranking model to  prioritize pipelines for inspection and manage its inspection resources.  The purpose of PHMSA’s RRIM is to generate a risk score for each  federally inspected pipeline and help determine the frequency of  inspection. RRIM incorporates data on a variety of pipeline  characteristics, which PHMSA calls threat factors, including a few  associated with material and corrosion failures. Those threat factors  include:  steel pipe that lacks a protective external coating, also known as “bare  steel;”  steel pipe that was coated ineffectively, in such a way that the  external coating may no longer adhere to the pipe; and  steel pipe that was manufactured using a technique common from the  1920s until the 1970s, known as low frequency electric-resistance  welding, that is susceptible to catastrophic failure and certain types of  corrosion.
PHMSA inspectors collect these data from operators during integrated  inspections for each pipeline segment, or unit, they inspect. PHMSA  officials said RRIM is designed to incorporate various threats and is not  limited to material or corrosion threats. Other threat factors that PHMSA  uses in RRIM include commodity type, recent significant incidents, and  recent enforcement actions. According to PHMSA officials, integrated  inspections are tailored to each operator and include reviews of operator  maintenance, repair, and other records and visits to pipeline locations to  assess cathodic protection or observe other activities.
On an annual basis, PHMSA uses RRIM to calculate a risk score for each  pipeline unit to determine the frequency of integrated inspections.  PHMSA assigns a weight to each threat factor in RRIM, based on data  the agency collects. For example, PHMSA assigns a weight of 2 to  pipeline units where operators report that ineffective coating is present, as  shown in table 6. The weights are then added together and multiplied by  the consequence index of the unit. The resulting number is the unit risk  score, which is averaged across the units that comprise each inspection  system, which is the level at which PHMSA conducts integrated  inspections. The inspection system’s risk score determines whether the  system is assigned to the high, medium, or low risk tier, and inspected at  least every 3, 5, or 7 years, respectively.
Annually, PHMSA officials use RRIM to identify inspection system  priorities for the next year, based on the risk tier and the amount of time  since the system’s most recent inspection. Each year PHMSA inspects a  portion of the total number of inspection systems, which in 2016 totaled  655 systems. For example, in 2016, PHMSA used RRIM to prioritize a list  of 79 systems to be inspected in 2017. Of these systems prioritized for  inspection, 29 percent were considered high risk, 53 percent were  medium risk, and 18 percent were low risk. In addition, based on the  criteria PHMSA established for inspecting high, medium, and low risk  systems at least once every 3, 5, and 7 years, respectively, each of these  79 systems were due for inspection. PHMSA officials said this approach  allows them to allocate inspection resources to pipelines considered  higher risk, while ensuring that all inspection systems are inspected at  least every 7 years. PHMSA officials noted that a risk-based inspection  approach is necessary given the size of the federally regulated pipeline  network and the number of its inspection staff.
PHMSA officials said RRIM is the primary tool they use across their  regional offices and interstate agents to prioritize and schedule  inspections but said they also consider input from regional inspection staff  as part of this process. Each year, PHMSA headquarters officials provide  the list of inspection priorities generated by RRIM to the regional offices,  and inspectors have the opportunity to review the list and provide  feedback. Regional inspectors told us that during these reviews they use  their knowledge of local operators and pipelines to recommend that  certain pipeline units be given higher or lower priority than they are  ranked by RRIM. Regional inspectors said RRIM is generally effective in  prioritizing inspections, but there are threats that it may not capture, such  as the management experience of an operator, or whether there has  been recent public concern regarding a particular pipeline. For those  interstate pipelines inspected by states’ pipeline safety offices designated  as interstate agents, state officials said they also have the opportunity to  review PHMSA’s inspection priorities and suggest additional priorities.
section_title: PHMSA Has Taken Some Steps to Improve Data Quality to Enhance Its Risk Ranking Index Model
paragraphs: In recent years, PHMSA has taken steps to improve the quality of the  data used in RRIM. In June 2012, the Department of Transportation’s  Office of Inspector General identified a number of long-standing data  management deficiencies at PHMSA that have limited its ability to  conduct meaningful analysis to improve its oversight. Among the  concerns, the Inspector General found that shortcomings in PHMSA’s  data management and quality limited the usefulness of operator incident  and annual reports in identifying pipeline safety risks. PHMSA officials  told us that in recent years they have implemented a number of  procedures to limit errors and improve the accuracy of data submitted by  operators. For example, under PHMSA’s internal data management  procedures, officials stated that they review all incident report  submissions from operators on a monthly basis to ensure they are  complete and to identify outlier data entries. PHMSA officials also said  they review a spreadsheet of all unit data that can be confirmed in  operator-submitted annual reports and compare data entries with those  submitted by operators in prior years to detect data anomalies.
Although PHMSA has taken some steps to improve data quality, PHMSA  officials identified other limitations with their current data collection that  hinder their ability to enhance the data used in RRIM. Officials stated that  RRIM does not include all the threat factors they would like to use  because they have not collected certain data at the unit level, which is the  level at which the model calculates risk scores. For example, officials said  they would like to use data on maximum allowable operating pressure as  a threat factor for RRIM, but PHMSA’s current data on operating pressure  are collected in aggregate at the state level for each operator and not at  the unit level. In addition, officials noted that the data do not allow  PHMSA to identify the precise location of threats such as ineffective  external coating or certain types of welding associated with corrosion, and  therefore PHMSA cannot determine whether threat factors are co-located  and potentially correlated. To help address this limitation, PHMSA has  developed a form that enables inspectors to systematically collect  additional data at the unit level during an inspection. While this approach  could improve the quality of data in RRIM these data will not be  immediately available, since the inspection systems are inspected every  3, 5, or 7 years based on their risk score.
To address these limitations, PHMSA has sought to expand its data  collection through the National Pipeline Mapping System, a geographic  information system managed by PHMSA, which officials said would  strengthen the accuracy and precision of the data used in RRIM. In  June 2016, PHMSA issued a public notice to expand its information  collection authorities to collect pipeline data from operators at a positional  accuracy of approximately 100 feet, which is significantly more precise  than the pipeline unit, which in 2017 averaged over 200 miles in length.  This data collection would include threats associated with corrosion  prevention, such as whether the pipe is externally coated, and how the  pipe was welded, among other pipeline characteristics. However, in its  March 2017 decision memo, OMB declined PHMSA’s proposal to collect  these additional data, but the memo did not provide a reason for this  decision. PHMSA officials said they are evaluating their next steps and  plan to propose a revision to their data collection that does not impose  excessive burden on stakeholders before PHMSA’s current data  collection authority expires in 2020.
More broadly, as part of its strategic plan, PHMSA is taking steps to  better align its organizational structure with the need for a consistent  approach to how it collects, manages, and uses data. In 2016, PHMSA  established the Office of Planning and Analytics, whose mission is to  support a data-driven approach to PHMSA’s oversight by leading  strategic planning and analytical projects. According to PHMSA, the  establishment of the Office of Planning and Analytics will support  PHMSA’s efforts to become a data-driven and risk-based safety agency.
section_title: PHMSA Has Not Documented Its Decisions or Validated the Effectiveness of Its Risk Ranking Index Model
paragraphs: Although PHMSA has taken steps to improve the quality of data used in  RRIM, PHMSA did not document key decisions and the rationale used to  design RRIM. Specifically, in designing RRIM, PHMSA did not document  its rationale for the selection of threat factors and their associated  weights, or the thresholds for risk tiers, and the frequency of inspection  associated with each risk tier. Standards for Internal Controls in the  Federal Government state that documentation is necessary to  demonstrate the design, implementation, and operating effectiveness of a  program. Additionally, OMB’s risk analysis principles state that agency  risk analyses should be based upon the best available scientific  methodologies, information, data, and weight of the available scientific  evidence, and that the rationale for the judgments used in developing a  risk assessment should be stated explicitly.
PHMSA officials said they used professional judgment to select threat  factors, to determine their associated weights, and to establish the risk  tiers and inspection frequency, but they did not document the rationale or  justification for their decisions, including how, if at all, they used data as  part of developing this approach.
Selection of threat factors and weights: PHMSA officials said that  certain threat factors, such as mileage of bare pipe and ineffective  coating, are generally known in the pipeline industry as problematic,  but officials did not document their decisions for how they determined  the selected weights or for how, if at all, they used data to develop the  values for the weights. The officials said they conducted sensitivity  analyses to calibrate the threat factor weights when they designed  RRIM in 2012, but did not document these analyses.
Thresholds for risk tiers: Similarly, PHMSA did not document how it  established the risk tiers and inspection frequency, or the rationale for  those decisions. PHMSA officials consider any inspection system with a score of 30 or more as high risk, more than 5 but less than 30 as  medium risk, and less than 5 as low risk. PHMSA officials said the  thresholds for the risk tiers were determined based on their  professional judgment that 25 percent of inspection systems should  be considered high risk, 50 percent medium risk, and 25 percent low  risk to ensure a relatively consistent workload across regions. Officials  said they determined inspection frequencies of 3, 5, and 7 years  based on professional judgment, noting that each inspection system  should be inspected at least once every 7 years and that the highest  risk systems did not require inspection more than once every 3 years.  However, PHMSA did not document the rationale for the decisions  made or how, if at all, data informed their decision-making process.
PHMSA officials told us that although they did not document these  decisions, which were made based on their professional judgment, they  solicit and receive feedback from PHMSA inspectors each year on the list  of inspection systems generated by RRIM, a step that serves as a check  on RRIM’s effectiveness. However, without documentation, the rationale  for key decisions and assumptions made as part of designing and  implementing RRIM is unclear. For example, RRIM’s design places a  greater relative weight on longer pipeline units, assuming that longer  pipeline segments have greater relative risk than shorter units. In 2016,  the average length of a high risk inspection system was 1,841 miles; the  average length of a medium risk inspection system was 358 miles, and  the average length of a low-risk system was 49 miles. Moreover, in 2016  RRIM assigned approximately 1 percent of all pipeline miles inspected by  PHMSA as low risk (7-year inspection cycle) and more than 70 percent as  high risk (3-year inspection cycle). While this generally results in more  frequent inspections for longer pipeline systems—which may be desirable  from PHMSA’s perspective—without documentation, the rationale for the  chosen mileage weighting and the assumed risk of this factor relative to  other factors is unclear.
In addition to a lack of documentation, PHMSA lacks a process that uses  data to assess the ongoing effectiveness of RRIM and validate that it  appropriately prioritizes inspections. Leading management practices and  principles have highlighted the importance of periodic review and  evaluation of risk management approaches. Specifically, OMB’s risk  management principles state that the risk management process must be  subjected to regular review to assess potential changes in risks, their  likelihood and impact, and deliver assurance that the risk management  process remains appropriate and effective. In addition, Standards for  Internal Controls in the Federal Government states that management  should use quality information to make informed decisions and evaluate  program performance in achieving key objectives and addressing risks.  Similarly, PHMSA’s strategic plan includes an objective to use data more  effectively to improve its risk-based approach to inspection.
PHMSA officials said they have not established a data-driven process to  assess the effectiveness of RRIM because they believe that it has been  an effective tool for prioritizing inspections for its staff. The officials said  that they conducted sensitivity analyses to calibrate the weights in RRIM  when they first designed it in 2012, but did not document those analyses,  and they have made periodic changes to RRIM, such as adding threat  factors or adjusting weights, based on their professional judgment.  However, it is unclear what impact these changes have had on the  effectiveness of RRIM, as PHMSA officials could not provide  documentation of any analyses to support why these changes were made  and their impact on RRIM’s results. PHMSA officials noted that the Office  of Planning and Analytics has begun evaluating potential strategies to  improve RRIM’s risk-modeling capabilities, and to examine how the  officials could use existing data to validate RRIM. They also noted that  they have recently transitioned RRIM to an operating system that will  allow PHMSA to make adjustments more frequently as data are collected  and updated. However, officials further noted that these activities are in  their initial stages, and that PHMSA has not yet developed tangible steps  to assess RRIM.
Without a process that uses data to assess the effectiveness of RRIM,  PHMSA is unable to demonstrate the validity of RRIM and whether it is  effectively prioritizing pipelines for inspection. For example, Standards for  Internal Controls in the Federal Government notes that activities such as  comparing actual performance to planned or expected results and  analyzing significant differences can help organizations achieve  objectives. In the context of RRIM, such an analysis could compare the  characteristics of pipeline segments involved in recent incidents to  pipeline segments assigned to each risk tier by RRIM. This analysis could provide a basis for PHMSA to assess the validity of the threat factors and  weighting and to make adjustments over time that would improve RRIM.  However, without a process that includes these types of activities,  PHMSA lacks assurance that RRIM prioritizes inspections effectively and  that its inspection approach maximizes safety benefits to the public.
section_title: Conclusions
paragraphs: While pipelines are a relatively safe mode of transporting inherently  dangerous materials, an incident can pose a profound threat to life,  property, and the environment. Though individual pipeline operators  deploy a variety of materials and corrosion prevention technologies to  guard against these threats, PHMSA has an important role in overseeing  operator actions to ensure pipeline safety. Moreover, as PHMSA  acknowledges, the size and diversity of the nation’s 2.7-million mile  pipeline network necessitates a risk-based approach to oversight.  However, because PHMSA has not documented the basis for the design  and key decisions of RRIM and has not formally evaluated its  effectiveness at prioritizing pipelines for inspection, it is unclear how  effectively the model has helped PHMSA manage its inspection  resources or maximize safety benefits to the public. Federal management  practices and principles identify the need to document decisions, to use  the best available data and information to drive decisions, and to  periodically assess key management activities. In the context of RRIM,  these actions are complementary as documentation of its design could  serve as a baseline for a data-driven evaluation of its effectiveness and a  review of whether the assumptions and decisions made as part of the  design are valid. Such an evaluation could complement the analytical  projects planned by PHMSA’s Office of Planning and Analytics to support  a data-driven approach to PHMSA’s oversight. Furthermore, these  actions could help PHMSA refine and improve its proposal for more  specific data collection through the National Pipeline Mapping System  before PHMSA’s current data collection authority expires in 2020 and  help PHMSA make progress toward its goal of becoming a more data- driven and risk-based safety agency.
section_title: Recommendations for Executive Action
paragraphs: To assess and validate the effectiveness of PHMSA’s RRIM in prioritizing  pipelines for inspection, we recommend that the Secretary of  Transportation direct the Administrator of PHMSA to take the following  two actions: document the decisions and underlying assumptions for the design of  RRIM, including what data and information were analyzed as part of  determining each component of the model, such as the threat factors,  weights, risk tiers, and inspection frequency. establish and implement a process that uses data to periodically  review and assess the effectiveness of the model in prioritizing  pipelines for inspection and document the results of these analyses.
section_title: Agency Comments
paragraphs: We provided the Department of Transportation and NTSB with a draft of  this report for review and comment. In its comments, reproduced in  appendix III, the Department of Transportation concurred with our  recommendations. The Department of Transportation and NTSB also  provided technical comments, which we incorporated as appropriate.
We are sending copies of this report to relevant congressional  committees, the Secretary of Transportation, the Chair of NTSB, and  other interested parties. In addition, this report will also be available at no  charge on GAO’s website at http://www.gao.gov.
If you or your staff have any questions about this report, please contact  me at (202) 512-2834 or flemings@gao.gov. Contact points for our  Offices of Congressional Relations and Public Affairs may be found on  the last page of this report. GAO staff who made key contributions to this  report are listed in appendix IV.
section_title: Appendix I: Additional Observations on Pipeline Materials and Corrosion Prevention Technologies
paragraphs: The Protecting our Infrastructure of Pipelines and Enhancing Safety Act  of 2016 included a provision for GAO to consult with stakeholders to  gather information on the range of pipeline materials used in the United  States and other developed countries and the effectiveness of corrosion  control techniques. This appendix provides perspectives obtained from  interviews with a nongeneralizable sample of eight pipeline operators and  eight additional stakeholders with expertise on pipeline materials and  corrosion (expert stakeholders) on (1) the use of pipeline materials and  corrosion prevention technologies internationally, and (2) the potential  improvements in pipeline materials and corrosion prevention  technologies.
Operators and expert stakeholders we interviewed noted few differences  between the types of pipeline materials and corrosion technologies used  in the United States gas and hazardous liquid network compared to their  counterparts in Canada and European Union countries. Specifically, a  majority of operators and expert stakeholders stated that the use of steel,  plastic, composites, and other materials in pipelines in the United States  is very similar to their use in Canada and the European Union, though  these expert stakeholders and operators noted some minor differences in  the use of these materials. For example, in comparison with the United  States, three expert stakeholders noted that Canada may have wider use  of higher grade steel—to provide strength for pipelines to operate at high  operating pressures but with a thin pipeline wall—and one expert  stakeholder said the European Union uses plastic and composites more  widely in its network. A few of these expert stakeholders attributed these  differences to less conservative design standards in Canada and the  European Union than in the United States. Similarly, most of the  operators and expert stakeholders we interviewed stated that similar  corrosion prevention technologies used in the United States are  commonly used throughout Canada and the European Union. For  example, operators and expert stakeholders stated that coatings are  commonly used to prevent external corrosion in the United States,  Canada, and the European Union, though two operators and expert  stakeholders said European Union countries often make more  widespread use of a three-layer polyethylene coating than is used in the  United States. In addition, two operators and expert stakeholders said  the European Union’s regulatory approach is more flexible at  accommodating new technologies than the approach taken in the United  States.
Operators and expert stakeholders were divided on the extent of future  improvements in materials. For example, several operators and expert  stakeholders stated that they anticipate pipeline operators will increase  the use and development of higher grade steel. These operators and  expert stakeholders noted these changes could include minor  improvements in steel manufacturing to produce more widespread use of  higher strength steel, but noted that pipelines manufactured with higher  grade steels often have thinner walls and are less resistant to third-party  damage. Additionally, a few operators and expert stakeholders stated that  they anticipate further development of plastics and increased use of  plastics across the pipeline network. For example, one expert stated that  he expects the use of polyamide plastics, which are currently used in less  than 1 percent of distribution pipelines, to be more widely used and at  higher pressures in the future. In contrast, several operators and expert  stakeholders stated that they anticipate few changes in pipeline materials  in the next 10 years, noting that current materials (i.e., steel and plastic)  are well known by the pipeline industry and have been successful in  addressing corrosion challenges.
Similarly, operators and expert stakeholders had mixed opinions on  whether there would be significant improvements in corrosion prevention  technologies over the coming years. For example, several operators and  expert stakeholders characterized coatings and cathodic protection as  mature technologies and did not foresee significant further development  in the next 10 years. In contrast, other operators and expert stakeholders  stated that they expected that improvements in monitoring, data collection  and analysis might help operators improve efforts to combat internal  corrosion. For example, these operators and expert stakeholders  anticipate greater use of automatic monitoring technology to provide  continual information on pipeline conditions, and improved integration of  cathodic protection data with other monitoring efforts. Operators and  expert stakeholders also identified improved coating technology as a  potential area for advancement, with one expert stakeholder noting that  nanotechnology may be used to develop self-repairing coatings that do  not require operators to excavate pipelines to repair.
section_title: Appendix II: Objectives, Scope and Methodology
paragraphs: The objectives of this report were to determine (1) the pipeline materials  and corrosion prevention technologies that are used in the gas and  hazardous liquid pipeline network and their respective benefits and  limitations; (2) how selected pipeline operators train personnel to manage  corrosion and the challenges that exist in ensuring personnel are  qualified, and (3) how the Pipeline and Hazardous Materials Safety  Administration (PHMSA) uses data on pipelines and corrosion prevention  to inform its inspection priorities. In addition to the methodology described  below, for each of these objectives, we reviewed pertinent PHMSA  regulations, documents, and interviewed PHMSA headquarters officials.  This report also includes information on the use of pipeline materials and  corrosion prevention technologies outside the United States as well as  potential future improvements in materials and corrosion prevention  technologies, based on interviews with the selected operators and expert  stakeholders. (See app. I.)
To determine what pipeline materials and corrosion prevention  technologies are used to transport hazardous liquids and benefits and  limitations, we analyzed the most recent full-year data (calendar years  2010–2015) on pipeline characteristics, including data on mileage,  geography, materials transported, and pipeline materials and corrosion  prevention technologies reported to PHMSA by pipeline operators. We  also analyzed PHMSA data on the cause of pipeline incidents from 2010– 2015. We did not review data prior to 2010 due to a significant change in  PHMSA’s reporting requirements in 2009 that PHMSA officials noted  limits comparability of the data collected prior to that change. We did not  review operator-reported data after 2015 because operator data from  2016 on pipeline characteristics was not expected to be finalized until  June 2017, according to PHMSA. We assessed the data’s reliability by  reviewing PHMSA reports, analyzing the data to identify any outlier  values, and interviewing PHMSA officials. We found the data to be  sufficiently reliable for the purposes of answering this objective. We also  reviewed Department of Transportation reports and academic literature  on the benefits and limitations of various materials and corrosion  prevention technologies.
We also interviewed a nongeneralizable sample of eight pipeline  operators and eight additional stakeholders with expertise on pipeline  materials and corrosion (expert stakeholders). (See table 7.) These  expert stakeholders represented entities including consultants, research  organizations, and other organizations. To obtain a diverse set of  viewpoints from pipeline operators, we selected operators based on  descriptive data collected by PHMSA on an operator’s pipeline network  function (gathering, transmission, or distribution); the types of materials  transported by the operator’s network; the size (miles of pipeline) of an  operator’s pipeline network and the geographic dispersion; and  recommendations from other stakeholders. We identified an initial pool of  expert stakeholders by reviewing academic literature, prior GAO work,  and trade publications, and based on recommendations made by officials  we interviewed from the National Transportation Safety Board, staff from  industry trade associations, and other industry stakeholders. We selected  expert stakeholders based on their knowledge of pipeline materials and  corrosion, as determined from a review of their professional qualifications  and experience or position related to these topics, as well as  recommendations of other stakeholders. To verify their expertise, we  obtained a curricula vitae, resume, or other biographical information, and  confirmed their qualifications during the interview. We also asked pipeline  operators and expert stakeholders for recommendations on other expert  stakeholders during our interviews with them.
Our goal in talking to these operators and expert stakeholders was to  collect a diverse set of perspectives on our questions and in doing so,  there were operators and expert stakeholders we included because of  their viewpoint to provide overall balance to the nonprobability,  nongeneralizable sample. To mitigate any potential biases in our sample,  we selected individuals with significant relevant experience or knowledge  who represented a range of alternative perspectives. We assessed this  criterion by reviewing the information used to confirm their qualifications  and verifying that the individuals have the expertise to participate in our  sample. Prior to conducting these interviews, we conducted two pretests  to obtain feedback on the questions. We conducted a semi-structured  interview with each operator and expert stakeholder and asked each  stakeholder the same set of questions. Because broad agreement existed  across the operators and expert stakeholders for many of these topics  and our sample was non-generalizable, we used indefinite quantifiers to  describe the responses. (See table 8.) The views provided by pipeline  operators and these expert stakeholders cannot be generalized across all  pipeline operators or expert stakeholders on these topics, but do provide  perspectives on the benefits, limitations, factors affecting costs and other  aspects of the pipeline materials and corrosion prevention technologies  discussed by these stakeholders. Furthermore, we did not attempt to  identify all pipeline materials or all corrosion technologies. Rather, this  information was obtained to provide a variety of perspectives on topics  related to pipeline materials and corrosion and relevant to our objective.
To analyze how selected operators train personnel to manage corrosion  and ensure that personnel were qualified, we reviewed PHMSA  regulations and proposed changes to those regulations requiring that  pipeline operator personnel are qualified for operational and maintenance  tasks, including corrosion prevention activities. We reviewed pipeline  operators’ training plans and other documentation. We interviewed staff  from 17 stakeholders: 8 pipeline operators, the same as selected above;  3 unions: the International Union of Operating Engineers, the Laborers’  International Union of North America, and the Utility Workers Union of  America; 3 training providers: the American Society of Mechanical  Engineers, the National Association of Corrosion Engineers, and  Veriforce; and 3 industry trade associations: the American Gas  Association, the American Petroleum Institute, and the Interstate Natural  Gas Association of America. These stakeholders were selected to provide  a range of views on approaches, common practices, and challenges  associated with corrosion training and operator qualification; however,  these views are not generalizable across all industry stakeholders.
To determine how PHMSA uses data on pipelines and corrosion to inform  its inspection priorities, we analyzed and assessed the reliability of the  most recent PHMSA inspection and enforcement data (calendar years  2014–2016) on pipeline materials and corrosion prevention technologies.  To assess the reliability of the data used for this objective, we reviewed  PHMSA and Department of Transportation Office of Inspector General  reports and PHMSA documentation, analyzed the data to identify any  outlier values and interviewed PHMSA officials. We also reviewed the  Oak Ridge National Laboratory’s assessment of PHMSA’s data  management and analysis capabilities and challenges. We also  interviewed PHMSA officials about how the data were collected, stored  and validated. We determined that the data were sufficiently reliable for  the purposes of addressing this objective. We evaluated PHMSA’s use of  this data in its risk-ranking index model as part of its effort to rank the  relative risk of pipelines and prioritize its annual inspections of pipeline  operators using these rankings. We compared this approach to criteria  identified in GAO’s Standards for Internal Controls in the Federal  Government, criteria for risk analysis developed by the Office of  Management and Budget (OMB), and PHMSA’s strategic objectives. In  addition, we reviewed Department of Transportation reports on PHMSA’s  risk management models and approaches and interviewed former  PHMSA officials about these topics. We also interviewed staff from each  of PHMSA’s five regional offices, which are responsible for conducting  inspections of pipeline operator operations, and conducted a group  interview of state officials from all nine interstate agents to understand  how inspection data is collected and used to inform PHSMA’s oversight.
We conducted this performance audit from July 2016 to August 2017 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.
section_title: Appendix III: Comments from the Department of Transportation
section_title: Appendix IV: GAO Contact and Staff Acknowledgments
subsections: section_title: GAO Contact
section_title: Staff Acknowledgments
paragraphs: In addition to the contact named above, Matt Barranca (Assistant  Director), Matt Voit (Analyst in Charge), Katrina Ballard, David Blanding,  Melissa Bodeau, David Hooper, Katrina Pekar-Carpenter, Adam  Peterson, Malika Rice, Jim Russell, and Jack Wang made key  contributions to this report.