PIPELINE SAFETY

Additional Actions 

Could Improve 

Federal Use of Data 

on Pipeline Materials 

and Corrosion

Report to Congressional Committees

August 2017

GAO-17-639

United States Government Accountability Office
United States Government Accountability Office

Highlights of GAO-17-639, a report to 

congressional committees

August 2017

PIPELINE SAFETY

Additional Actions Could Improve Federal Use of 

Data on Pipeline Materials and Corrosion

What GAO Found

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 corrosionresistant, 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. 

Application and Installation of Pipeline Coating and Cathodic Protection

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 datadriven evaluation process, PHMSA cannot demonstrate the effectiveness of the 

model it uses to allocate PHMSA’s limited inspection resources.

View GAO-17-639. For more information,

contact Susan Fleming at (202) 512-2834 or 

FlemingS@gao.gov.

Why GAO Did This Study

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. 

What GAO Recommends

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.
Page i GAO-17-639 Pipeline Safety

Letter 1

Background 5

Pipeline Operators Use Steel, Plastics, and Various Corrosion 

Prevention Technologies, Which Have a Range of Benefits and 

Limitations 12

Selected Pipeline Operators Reported Using a Variety of Sources 

for Pipeline Corrosion Training and Identified Challenges 

Ensuring Personnel Are Qualified 23

PHMSA Uses Data on Pipelines and Corrosion Prevention to 

Prioritize Inspections, but Lacks a Process to Assess and 

Validate the Effectiveness of Its Approach 28

Conclusions 37

Recommendations for Executive Action 37

Agency Comments 38

Appendix I Additional Observations on Pipeline Materials and 

Corrosion Prevention Technologies 39

Appendix II Objectives, Scope and Methodology 42

Appendix III Comments from the Department of Transportation 48

Appendix IV GAO Contact and Staff Acknowledgments 49

Tables

Table 1: Examples of Covered Tasks Related To Corrosion 10

Table 2: Percentage of Gas and Hazardous Liquid Pipeline 

Network Miles by Material, 2015 13

Table 3: Operator- and Expert Stakeholder-Identified Benefits 

and Limitations of Pipeline Materials 16

Table 4: Operator- and Expert Stakeholder-Identified Benefits

and Limitations of Various External Corrosion 

Protection Technologies 20

Contents
Page ii GAO-17-639 Pipeline Safety

Table 5: Operator- and Expert Stakeholder-Identified Benefits 

and Limitations of Various Internal Corrosion 

Prevention Technologies 22

Table 6: Selected Threat Factors and Weighting Used in the Risk 

Ranking Index Model of the Pipeline and Hazardous 

Materials Safety Administration (PHMSA), 2016 30

Table 7: Stakeholders with Specialized Expertise Selected for 

Interviews on Pipeline Materials and Corrosion 44

Table 8: Indefinite Quantifiers Used to Describe Frequency 

of Operator and Expert Stakeholder Views on Pipeline 

Materials and Corrosion Prevention Technologies 46

Figures

Figure 1: Gas and Hazardous Liquid Pipeline Network 6

Figure 2: Operator-Reported Causes of Significant Pipeline 

Incidents, 2010–2015 (1,737 total) 7

Figure 3: Example of External Coating and Cathodic Protection 

Installation and Application 9
Page iii GAO-17-639 Pipeline Safety

Abbreviations

ASME American Society of Mechanical Engineers 

NACE National Association of Corrosion Engineers

NTSB National Transportation Safety Board

OMB Office of Management and Budget

PHMSA Pipeline and Hazardous Materials Safety Administration

psi pounds per square inch

RRIM Risk Ranking Index Model

This is a work of the U.S. government and is not subject to copyright protection in the 

United States. The published product may be reproduced and distributed in its entirety 

without further permission from GAO. However, because this work may contain 

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necessary if you wish to reproduce this material separately.
Page 1 GAO-17-639 Pipeline Safety

441 G St. N.W.

Washington, DC 20548

August 3, 2017

The Honorable John Thune

Chairman

The Honorable Bill Nelson

Ranking Member

Committee on Commerce, Science and Transportation

United States Senate

The Honorable Bill Shuster

Chairman

The Honorable Peter DeFazio

Ranking Member

Committee on Transportation and Infrastructure

House of Representatives

The Honorable Greg Walden

Chairman

The Honorable Frank Pallone

Ranking Member

Committee on Energy and Commerce

House of Representatives

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.1 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.2 While pipeline incidents may be caused by a 

variety of factors, from 2010 through 2015, pipeline material and weld 

 1

In this report, we use the term gas to include natural gas, flammable gas, or gas that is 

toxic or corrosive.

2

In its regulations, PHMSA refers to the release of gas from a pipeline as an incident and 

a spill from a hazardous liquid pipeline as an accident. (49 C.F.R. §§ 191.3 and 195.50). 

For simplicity, this report will refer to both as incidents. 

Letter
Page 2 GAO-17-639 Pipeline Safety

failures and corrosion3 were the reported cause of about one-third of 

significant pipeline incidents across the pipeline network, according to 

data collected by PHMSA.4 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.5 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.6 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

Corrosion is defined by PHMSA as the deterioration of a material (usually a metal) that 

results from a reaction with its environment. 

4

PHMSA defines significant incidents in internal guidance as those including any of the 

following conditions: fatality or injury requiring in-patient hospitalization; $50,000 or more 

in total costs (in 1984 dollars); highly volatile liquid releases of 5 barrels or more or other 

liquid releases of 50 barrels or more; or liquid releases resulting in an unintentional fire or 

explosion. Gas distribution incidents caused by a nearby fire or explosion that affected the 

pipeline system are not considered significant incidents under this definition.

5

NTSB, Pipeline Accident Report: Columbia Gas Transmission Corporation Pipeline 

Rupture, Sissonville, West Virginia, December 11, 2012, NTSB/PAR-14/01 PB2014-

103977 (Washington, D.C.: Feb. 19, 2014). The NTSB is required by statute to investigate 

all civil aviation accidents and selected accidents in other modes—highway, marine, 

railroad, pipeline, and hazardous materials. 49 U.S.C. § 1131(a)(1). NTSB also has the 

authority to investigate any other accident related to the transportation of individuals or 

property when its board decides the accident is catastrophic or involves problems of a 

recurring character, or the investigation would help carry out NTSB authorities for accident 

investigation. 49 U.S.C. § 1131(a)(1)(F). 

6

Pub. L. No. 114-183, § 21, 130 Stat. 514, 528. 
Page 3 GAO-17-639 Pipeline Safety

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).7 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.8

To analyze how selected pipeline operators train personnel to manage 

corrosion, we reviewed PHMSA regulations and proposed changes to 

 7

For the purposes of this report, we refer to stakeholders with expertise on pipeline 

materials and corrosion as expert stakeholders.

8

While we collected information on benefits, limitations, and factors affecting cost from 

these interviews, we did not review cost-benefit analyses or conduct a formal cost-benefit 

analysis due to a lack of available data for pipeline materials and corrosion technologies 

across the network. In addition, while we asked operators and expert stakeholders about 

the cost of materials and corrosion prevention technologies during our interviews, many 

stated that they could not provide estimates for specific materials and technologies, in part 

because estimates depend on a variety of factors. As result, we reported on factors 

affecting the cost of these materials and technologies, rather than specific cost estimates.
Page 4 GAO-17-639 Pipeline Safety

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’s9 criteria for risk analysis 

developed by the Office of Management and Budget (OMB) and 

PHMSA’s strategic objectives.10 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.11 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 

 9

GAO, Standards for Internal Control in the Federal Government, GAO-14-704G 

(Washington, D.C.: Sept. 10, 2014).

10OMB, Updated Principles for Risk Analysis, OMB-M-07-24 (Washington, D.C.: Sept. 19, 

2007), and OMB, Management’s Responsibility for Enterprise Risk Management and 

Internal Control, Circular No. A-123 (Washington, D.C.: Jul. 15, 2016).

11“Interstate agents” are authorized by PHMSA to assist with the inspection of interstate 

pipelines. 49 U.S.C. § 60106. Of the nine states designated as interstate agents, four 

states (Connecticut, Michigan, Iowa, and Ohio) are designated solely as interstate agents 

for natural gas; one state is designated solely as an interstate agent for hazardous liquids 

(Virginia), and four states (Arizona, Minnesota, New York and Washington) are designated 

for both. 
Page 5 GAO-17-639 Pipeline Safety

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.

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.12

 12Certain types of gathering pipelines are not regulated by PHMSA. 49 U.S.C. §60101(b). 

For example, PHMSA only regulates gas gathering pipelines in non-rural areas, resulting 

in regulation and inspection of approximately 5 percent of gas gathering pipelines and 

approximately 10 percent of hazardous liquid pipelines. Our prior work has noted that 

PHMSA lacks data on unregulated gathering pipelines, and recommended that the agency 

collect data on these pipelines, comparable to what is currently collected for regulated 

gathering pipelines, in order to enhance pipeline safety. See GAO, Pipeline Safety: 

Collecting Data and Sharing Information on Federally Unregulated Gathering Pipelines 

Could Help Enhance Safety, GAO-12-388 (Washington, D.C.: Mar. 22, 2012). This 

recommendation remains open. PHMSA has proposed regulations to collect additional 

data on gathering pipelines for gas and hazardous liquids but these rules have not yet 

been finalized by PHMSA. See 80 Fed. Reg. 61610 (Oct. 13, 2015) and 81 Fed. Reg. 

20722 (Apr. 8, 2016).

Background
Page 6 GAO-17-639 Pipeline Safety

Figure 1: Gas and Hazardous Liquid Pipeline Network

Note: Oil products are also transmitted from the refinery through transmission pipelines to storage 

tanks and other facilities not depicted in this figure.

• 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).13 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

 13For the purposes of this report, we use the term transmission pipeline to refer to both 

gas and hazardous liquid pipelines carrying product over long distances to users.
Page 7 GAO-17-639 Pipeline Safety

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.

Figure 2: Operator-Reported Causes of Significant Pipeline Incidents, 2010–2015 

(1,737 total)

Note: PHMSA defines significant pipeline incidents in its internal guidance as those including any of 

the following conditions: fatality or injury requiring in-patient hospitalization; $50,000 or more in total 
Page 8 GAO-17-639 Pipeline Safety

costs (in 1984 dollars); highly volatile liquid releases of 5 barrels or more or other liquid releases of 50 

barrels or more; or liquid releases resulting in an unintentional fire or explosion. Gas distribution 

incidents caused by a nearby fire or explosion that affected the pipeline system are not considered 

significant incidents under this definition.

PHMSA has established regulations that identify requirements for pipeline 

materials and corrosion prevention technologies in the gas and 

hazardous liquid pipeline network.14 PHMSA’s regulations identify design 

standards for pipelines and regulate what materials can be used under 

different operating conditions and pressures.15 For corrosion prevention, 

external coatings and a technology known as cathodic protection are 

required for metallic pipes installed beginning in 1971.16 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.17 External coatings and cathodic protection 

thus work together to protect the pipeline by disrupting the chemical 

process that leads to corrosion. (See fig. 3.)

 1449 C.F.R. § 192.451–491 (gas); 49 C.F.R. § 195.551–591 (hazardous liquids).

1549 C.F.R. § 192.101–125 (gas); 49 C.F.R. § 195.100–134 (hazardous liquids).

16Operators are required to cathodically protect metallic pipelines installed before 1971 in 

which active corrosion is found in (1) bare or ineffectively coated transmission lines; (2) 

bare or coated pipes at compressor, regulator, and measuring stations, or (3) a bare or 

coated distribution line. (49 C.F.R. § 192.457 (b)). 

17According to PHMSA, cathodic protection systems help prevent corrosion from occurring 

on the exterior of pipes by substituting a new source of electrons, commonly referred to as 

a “sacrificial anode” or “impressed current anode.” Both systems operate by imparting a 

direct current onto the buried pipeline, using devices called rectifiers. As long as the 

current is sufficient, the corrosion is prevented, or at least mitigated and held in check. 
Page 9 GAO-17-639 Pipeline Safety

Figure 3: Example of External Coating and Cathodic Protection Installation and 

Application

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.18 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.19 In its operator 

qualification regulations, PHMSA has stated its objective is to reduce the 

risk of accidents on pipelines attributable to human error.20 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 

 18Pub. L. No. 107-355, § 14(a), 116. Stat. 2985, 3002 (2002) (codified as amended at 49 

U.S.C. § 60109(c)(3)(A)-(B)). PHMSA defines “high-consequence areas” differently for 

gas and hazardous liquid. For gas, high-consequence areas typically include highly 

populated or frequented areas, such as parks (49 C.F.R. § 192.903). For hazardous liquid, 

high-consequence areas include highly populated areas, other populated areas, navigable 

waterways, and areas unusually sensitive to environmental damage.

1949 C.F.R. § 192.801-809 (gas); 49 C.F.R. § 195.501–509 (hazardous liquids).

2064 Fed. Reg. 46853 (Aug. 27, 1999). 
Page 10 GAO-17-639 Pipeline Safety

evaluate whether individuals are qualified to perform those tasks.21 (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.22 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. 23

Table 1: Examples of Covered Tasks Related To Corrosion 

Example Definition

Measure external corrosion Investigate the extent of external corrosion and record data.

Coating application and repair: Sprayed Prepare the surface (e.g., exterior of a pipe) and apply or repair coating using a sprayer.

Troubleshoot active cathodic protection 

system

Determine the reason for the cathodic protection system’s failure and identify the required 

corrective action.

Source: American Society of Mechanical Engineers (ASME), Pipeline Personnel Qualification, ASME Code for Pressure Piping, B-31, ASME B31Q-2016. | GAO-17-639

Note: A covered task is an activity, identified by the operator, that: (1) is performed on a pipeline 

facility; (2) is an operations or maintenance task; (3) is performed as a requirement of this regulation; 

and (4) affects the operation or integrity of the pipeline. 49 C.F.R. § 192.801 (gas) and 49 C.F.R. § 

195.501 (hazardous liquids).

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.24 In the nine states designated as interstate agents, 

state pipeline inspection staff supplements PHMSA inspections, but 

PHMSA maintains enforcement authority over these pipelines. Regarding 

 21A covered task is an activity, identified by the operator, that: (1) is performed on a

pipeline facility; (2) is an operations or maintenance task; (3) is performed as a 

requirement of this regulation; and (4) affects the operation or integrity of the pipeline. 49 

C.F.R. § 192.801 (gas) and 49 C.F.R. § 195.501 (hazardous liquids).

2249 C.F.R. § 192.805(h) and 49 C.F.R. § 195.505(h).

2349 C.F.R. § 192.803, Subpart N and 49 C.F.R. § 195.503.

24The Federal Energy Regulatory Commission approves the construction of interstate 

pipelines by issuing a certificate of public convenience and necessity, which includes 

conditions that the pipeline company receive all required federal authorizations before 

beginning construction, if it has not already done so. 15 U.S.C. § 717.
Page 11 GAO-17-639 Pipeline Safety

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.25 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.26

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.27 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.28 The corrosion prevention data include information 

 2549 U.S.C. § 60105. States may adopt additional or more stringent standards so long as 

they are compatible with federal regulations. 49 U.S.C. § 60104(c).

26Under a certification, each state must file an annual progress report with PHMSA that 

includes information on all pipeline operators, incidents, and state-conducted inspection 

and enforcement activities. 49 U.S.C. § 60105(c).

27As defined by PHMSA, in 2016, the average length of a pipeline unit was 284 miles, 

while the average length of a pipeline inspection system is 706 miles. This length includes 

pipeline mileage and estimated mileage for facilities such as compressor stations, and 

underground storage facilities. 

28PHMSA defines composite as pipe that consists of two or more dissimilar materials 

layered together to be stronger than the individual materials. Examples include, but are 

not limited to, fiber reinforced plastic pipe, steel reinforced thermoplastic pipe, and metallic 

composite pipe. (Instructions for Form PHMSA F 7100.2-1).
Page 12 GAO-17-639 Pipeline Safety

on whether the pipeline is coated and cathodically protected, and other 

characteristics associated with corrosion.

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.29

 29To obtain information on pipeline materials and corrosion prevention technologies, we 

selected and interviewed a sample of eight pipeline operators and eight expert 

stakeholders and asked them about the use of these materials and technologies. 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 where appropriate, as defined in our methodology. See appendix II for 

more details.

Pipeline Operators 

Use Steel, Plastics, 

and Various 

Corrosion Prevention 

Technologies, Which 

Have a Range of 

Benefits and 

Limitations

Nearly All Federally 

Regulated Pipelines Are 

Constructed of Steel or 

Plastic, Which Involve 

Various Benefits, 

Limitations and Costs
Page 13 GAO-17-639 Pipeline Safety

Table 2: Percentage of Gas and Hazardous Liquid Pipeline Network Miles by 

Material, 2015

Material type Gatheringa Transmissionb Distributionc

Steel 95% 99% 35%

Plastic 4% 0.3% 62%

Composites

(consists of two or more dissimilar 

materials layered together)d

0% 0.002% N/A 

Other

(iron, copper, and other materials)e 1% 0.6% 3%

Source: GAO analysis of Pipeline and Hazardous Materials Safety Administration (PHMSA) data. | GAO-17-639

Note: Values may not total to 100 percent due to rounding.

a

PHMSA only collects data on federally regulated gathering pipelines. PHMSA estimates that only 5 

percent of gas gathering pipeline miles and about 10 percent of hazardous liquid pipelines are 

regulated.

b

Includes both gas transmission and hazardous liquid transmission pipelines.

c

Distribution refers to distribution of gas.

d

PHMSA data on composite materials are only reported separately from materials classified as “other” 

for gas transmission and gas gathering.

e

For hazardous liquids gathering pipelines, PHMSA classifies pipeline materials as “steel” or “nonsteel.” In 2015, there were 27 miles of non-steel hazardous liquid gathering miles reported to PHMSA 

by pipeline operators, which are classified as “other” in this table. These miles made up less than 1 

percent of all reported gathering miles.

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.30 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. Corrosionresistant steel alloys, such as stainless steel, are used in limited 

 3049 C.F.R. § 192.105(c) (gas); 49 C.F.R. § 195.106 (hazardous liquids). 
Page 14 GAO-17-639 Pipeline Safety

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.31 In 2015, PHMSA proposed changes to these regulations 

that would allow use of polyamide plastic pipelines at even higher 

operating pressures.32

• 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 

 3149 C.F.R. § 192.123.

3280 Fed. Reg. 29263 (May 21, 2015). This proposed rule has not yet been finalized. 
Page 15 GAO-17-639 Pipeline Safety

material proposed.33 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.34 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. 

 33Special permits are authorized by statute in 49 U.S.C. § 60118(c) and the application 

process is set forth in 49 C.F.R. §190.341.

34PHMSA officials noted that the agency has denied two applications, two applications 

were withdrawn, and two applications were under review as of March 2017. 
Page 16 GAO-17-639 Pipeline Safety

Table 3: Operator- and Expert Stakeholder-Identified Benefits and Limitations of Pipeline Materials

Material type Benefits Limitations

Steel • Greater strength than nonmetallic materials to 

accommodate high pressures

• Greater resistance to third-party damage (such as 

damage due to digging or excavation) than plastics, 

composites

• Only cost-effective material for higher transmission 

pressures and diameters

• Susceptible to corrosion and requires corrosion 

prevention technology such as coatings, which 

increases costs

• Steel generally costs more than plastic

• Higher installation costs than plastic

• Higher costs to weld steel than to fuse plastic

Plastic • Corrosion resistant

• Installation is simpler and quicker than steel, 

reducing cost

• Plastic material generally costs less than steel 

• Lacks strength for use at higher operating 

pressures and diameters

• More susceptible to third-party damage than steel

Compositesa • Corrosion resistant

• Installation is simpler and quicker than steel, 

reducing cost

• Some composites are better able to withstand 

pressure than plastic

• Generally lack strength for use at higher operating 

pressures, compared to steel

• Difficult to join with other pipelines 

Source: GAO analysis of operator and expert stakeholder information. | GAO-17-639

Note: The table above includes frequently identified benefits and limitations from analysis of 

interviews with eight pipeline operators and eight expert stakeholders.

a

The Pipeline and Hazardous Materials Safety Administration defines composites as pipe that 

consists of two or more dissimilar materials layered together to be stronger than the individual 

materials.

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.35

• 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 

 35A majority of operators and expert stakeholders provided only qualitative, rather than 

quantitative, information on the cost of materials. 
Page 17 GAO-17-639 Pipeline Safety

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.
Page 18 GAO-17-639 Pipeline Safety

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 1971.36

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.37 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 

 3649 C.F.R. § 192.455. 

37See also, Baker, Jr., Michael and Fessler, Ronald R., Pipeline Corrosion, Final Report 

to U.S. Department of Transportation, Pipeline and Hazardous Materials Safety 

Administration, Office of Pipeline Safety, DTRS56-02-D-70036 (November 2008). 

Most Federally Regulated 

Pipelines Use Corrosion 

Prevention Technologies, 

Which Involve Various 

Benefits, Limitations, and 

Costs

External Corrosion Prevention 

Technologies
Page 19 GAO-17-639 Pipeline Safety

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.38 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.39 (See table 

4.)

 38According to recommended practices published by NACE International, formerly the 

National Association of Corrosion Engineers (NACE), and incorporated into PHMSA’s 

regulations by reference, factors that are considered when selecting an external pipe 

coating include the type of environment, operating temperature on the existing pipelines, 

cost, and installation requirements. See NACE, Standard Practice Control of External 

Corrosion on Underground or Submerged Metallic Piping Systems, NACE SP0169-2013 

(Houston, TX: 2013). 

39In its report on the 2012 Sissonville pipeline incident, NTSB noted that various 

materials—such as tree roots, rocks, and disbonded coatings—can provide shielding of 

cathodic protection. NTSB concluded that the coarse rock covering the pipe most likely 

shielded the pipe from the cathodic protection current and contributed to the corrosion that 

caused the pipeline incident. NTSB/PAR-14/01, PB2014-103977.
Page 20 GAO-17-639 Pipeline Safety

Table 4: Operator- and Expert Stakeholder-Identified Benefits and Limitations of Various External Corrosion Protection 

Technologies

External corrosion 

protection technology Description Benefits Limitations

Fusion-bonded epoxy 

coating

Powder epoxy coating heatbonded to a pipeline. Standard 

modern coating.

• Does not block cathodic 

protection if the coating fails

• High adhesive rate

• Durable

• Protects against stress 

corrosion cracking 

• Effectiveness decreases at 

extreme temperatures

• Can be difficult to apply in the 

field

Three-layer 

polyethylene coating

System composed of a fusionbonded epoxy coating, adhesive 

and outer layer of polyethylene 

plastic.

• Resistant to soil stress

• Can be used at higher 

pressures

• Effective in wet environments

• May block cathodic protection 

if bonding fails

• Effectiveness decreases at 

extreme temperatures

• May have higher costs relative 

to other coatings

Tape wrap coating Tape composed of plastic or other 

material wrapped around a 

pipeline and welds.

• Operators and expert 

stakeholders we interviewed 

did not identify any benefits of 

tape wrap coating

• May block cathodic protection 

if bonding fails

• May be associated with stress 

corrosion cracking

• May have an overall higher 

failure rate

• Can be challenging to apply

Cathodic protection System that applies a small 

electrical current onto a pipeline. 

• Protects against external 

corrosion

• Complements coating 

• Rocks, stray current from 

nearby electric power cables, 

or failed coatings can block 

cathodic protection

• Requires access to electrical 

power

• Costs increase as coatings 

age

Source: GAO analysis of operator and expert stakeholder information. | GAO-17-639

Note: The table above includes frequently identified benefits and limitations from analysis of 

interviews with eight pipeline operators and eight expert stakeholders.

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.40 According to operators and expert 

 40Peabody, A.W, Peabody’s Control of Pipeline Corrosion, Ch.15: Economics, 2nd Ed. 

NACE International (2001). 
Page 21 GAO-17-639 Pipeline Safety

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.

Operators and expert stakeholders also identified internal corrosion 

prevention technologies along with their benefits and limitations.41 (See 

table 5.) According to PHMSA, many interrelated technical factors can 

affect the likelihood, aggressiveness, and location of internal corrosion.42

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.43 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.

 41PHMSA officials told us that they do not collect data on the use of internal corrosion 

prevention technologies because they are not widely used and their application is often 

customized to the specific product in the pipeline.

42In 2007, PHMSA polled its senior corrosion experts and other subject matter experts to 

obtain feedback on internal corrosion topics, including factors affecting internal corrosion. 

Among the factors contributing to internal corrosion, they noted that the product 

transported, the operating pressure, the presence of microbes, and other operating 

conditions can contribute to internal corrosion. See U.S. Department of Transportation, 

Internal Corrosion Control: A Regulatory Requirements Adequacy Review (Washington, 

D.C.: Dec. 31, 2007). 

43DTRS56-02-D-70036. 

Internal Corrosion Prevention 

Technologies
Page 22 GAO-17-639 Pipeline Safety

Table 5: Operator- and Expert Stakeholder-Identified Benefits and Limitations of Various Internal Corrosion Prevention 

Technologies

Internal corrosion 

technology Description Benefits Limitations

Additives (i.e., 

biocides and 

inhibitors)

Chemical compounds inserted into 

a pipeline that limit reactions that 

cause internal corrosion

• Biocides eliminate microbes in 

the pipeline

• Inhibitors block chemical 

reactions in the pipeline 

• Can be relatively expensive 

compared to other technologies

• Require multiple, periodic 

application

• May affect product quality

• May have negative 

environmental effects

Cleaning devices 

(known as “cleaning 

pigs”)

Specialized devices with brushes 

that are inserted into the pipeline to 

help eliminate water or debris that 

can cause corrosion

• Remove water or debris

• Complementary with additives 

and biocides

• Require the installation of 

infrastructure to insert and 

remove pigs in the pipeline

• Some pipelines cannot 

accommodate cleaning devices

• May require reduced flow rate 

during use

Dehydration systems Devices that remove moisture from 

and reduce the dew point in 

products

• Effective at removing moisture 

from gas 

• Can be relatively expensive 

compared to other technologies

• Recurring operational costs

Internal coatings and 

liners

Plastic liners or treatments that 

provide a barrier between the 

internal surface of a pipe and the 

transported products 

• Can be effective in highly 

corrosive environments

• Can improve flow velocity

• Can be relatively expensive 

compared to other technologies

• Can be challenging to install or 

repair

• Liners are not always 

compatible with cleaning 

devices 

Monitoring tools 

(such as in-line 

inspection devices)

Electronic tools that are inserted 

into the pipeline and provide 

information on the structural 

condition

• Provide real-time update on the 

status of corrosion and integrity 

of the pipeline

• Can be relatively expensive 

compared to other technologies

• Some pipelines cannot 

accommodate monitoring tools 

Source: GAO analysis of operator and expert stakeholder information. | GAO-17-639

Note: The table above includes frequently identified benefits and limitations from analysis of 

interviews with eight pipeline operators and eight expert stakeholders.

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 
Page 23 GAO-17-639 Pipeline Safety

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.

Gas and hazardous liquid pipeline operators use several sources to train 

personnel on pipeline corrosion, including in-house training and thirdparty 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.44 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.

 4449 C.F.R. § 192.805(h) and 49 C.F.R. §195.505(h).

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
Page 24 GAO-17-639 Pipeline Safety

• 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.45

• 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 

 45Midwest Energy Association is a trade association that provides training and events to 

utility and energy distribution companies.
Page 25 GAO-17-639 Pipeline Safety

should be able to perform, including corrosion-related tasks.46

Operators also use recommended practices from the American 

Petroleum Institute, including guidance that identifies 99 pipeline 

operational safety tasks, such as corrosion-related tasks.47

• 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 corrosionrelated 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.

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 

 46American Society of Mechanical Engineers, Pipeline Personnel Qualification: ASME 

Code for Pressure Piping, ASME B31Q-2016 (New York, NY: Aug. 30, 2016). 

47American Petroleum Institute, Recommended Practice for Pipeline Operator 

Qualification, RP 1161 (Washington, D.C.: January 2014).

Stakeholders Stated 

PHMSA’s Operator 

Qualification 

Requirements May 

Present Challenges for 

Pipeline Operators, 

Contractors, and PHMSA
Page 26 GAO-17-639 Pipeline Safety

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.48 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.

 48The third union we interviewed represented direct employees of utility companies, rather 

than contractors.
Page 27 GAO-17-639 Pipeline Safety

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.49 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.50 Moreover, PHMSA officials said 

that operators do not always review their covered tasks, evaluations, 

 4980 Fed. Reg. 39916 (July 10, 2015).

5080 Fed. Reg. 39916 (July 10, 2015). 
Page 28 GAO-17-639 Pipeline Safety

and procedures to ensure they are effective.51 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.52

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.

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.

 51In our interviews, operators identified a variety of approaches that they use to measure 

training effectiveness.

5282 Fed. Reg. 7972 (Jan. 23, 2017) (codified at 49 C.F.R. Parts 190, 191, 192, 195 and 

199).

PHMSA Uses Data 

on Pipelines and 

Corrosion Prevention 

to Prioritize 

Inspections, but 

Lacks a Process to 

Assess and Validate 

the Effectiveness of 

Its Approach
Page 29 GAO-17-639 Pipeline Safety

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.53 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.54

 53PHMSA inspects interstate gas transmission and hazardous liquid pipelines, which 

represent approximately 20 percent of the federally regulated pipeline network; the 

remaining 80 percent, which includes intrastate pipelines, are inspected by states’ pipeline 

safety offices. As part of its pipeline safety program, PHMSA provides guidance to state 

partners on how to use a risk-based approach to prioritize inspections. 

54According to PHMSA, integrated inspections combine several discrete inspection “types” 

(e.g., Unit Inspections, Operations and Maintenance Procedure Inspections, Integrity 

Management Inspections, etc.) into a single inspection that provides an integrated 

evaluation of an operator’s safety management programs. PHMSA prioritizes integrated 

inspections on specific areas based on system-specific risk information in order to apply 

PHMSA inspection resources to programs, geographic areas, and threats that pose higher 

risks.

PHMSA Uses Data on 

Pipelines and Corrosion 

Prevention to Prioritize 

Inspections
Page 30 GAO-17-639 Pipeline Safety

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.55 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.

Table 6: Selected Threat Factors and Weighting Used in the Risk Ranking Index Model of the Pipeline and Hazardous 

Materials Safety Administration (PHMSA), 2016 

Threat factor Description Weightinga

Unit miles The number of miles in each pipeline unit, which is the 

administrative division that PHMSA uses to manage its 

oversight of the pipeline network.

Weighted 0-3 based on the unit miles in 

proportion to total network miles. 

Pre-1970 low frequency 

electric resistance welding 

miles

The number of unit miles that were welded using low 

frequency electric-resistance welding prior to 1970, 

which is a risk factor for corrosion.

Weighted 0-3 based on the proportion of pre1970 low frequency electric resistance welding

miles to total network miles. 

Enforcement Enforcement actions over the last 7 years that involved 

the pipeline unit.

Weighted 0-3 based on type of enforcement 

action, if any.

Notification Notifications received by PHMSA of construction or 

acquisition involving the pipeline unit.

Weighted 2 for construction projects, 3 for 

acquisitions, or zero if none.

Commodity The product transported in the pipeline unit, such as 

hazardous liquids or natural gas.

Weighted 1-6 depending on the type of 

commodity.

Bare pipe mileage The number of unit miles that lack a protective external 

coating, which is a risk factor for corrosion.

Weighted 0-2 based on the proportion of bare 

pipe to unit miles.

Ineffective coating The number of unit miles where the protective external 

coating may not adhere to the pipe, which is a risk factor 

for corrosion.

Weighted 2 if ineffective coating is present, or 

zero if none.

Significant incidents Significant incidents, such as those involving a fatality, 

injury, or $50,000 or more in total costs, over the last 5 

years that involved the pipeline unit. 

Weighted 0-10 based on the number of 

incidents and other factors.

Source: GAO analysis of PHMSA information. | GAO-17-639

a

Within a given threat factor, greater weights indicate higher relative risks.

 55The consequence index is a PHMSA formula that calculates a value based on specific 

characteristics associated with each unit, including pipe diameter, commodity type, and 

whether the unit is located in a high consequence area. 
Page 31 GAO-17-639 Pipeline Safety

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.56

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.57

 56Our prior work has made recommendations supporting a risk-based approach to 

PHMSA’s oversight. See GAO, Gas Pipeline Safety: Guidance and More Information 

Needed before Using Risk-Based Reassessment Intervals, GAO-13-577 (Washington, 

D.C.: June 27, 2013). 

57State pipeline safety offices designated as interstate agents were responsible for 

inspecting approximately 12 percent of federally inspected pipeline miles in 2017. 
Page 32 GAO-17-639 Pipeline Safety

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.58 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.59 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 

 58 U.S. Department of Transportation, Office of Inspector General, Hazardous Liquid 

Pipeline Operators’ Integrity Management Programs Need More Rigorous PHMSA 

Oversight, AV-2012-140 (Washington, D.C.: June 18, 2012). 

59Specifically, the report recommended, among other things, that PHMSA establish 

additional quality assurance procedures to verify the accuracy of operator annual reports 

and accident data. This recommendation was implemented in 2013. 

PHMSA Has Taken Some 

Steps to Improve Data 

Quality to Enhance Its 

Risk Ranking Index Model
Page 33 GAO-17-639 Pipeline Safety

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.60 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.61

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.

 60The National Pipeline Mapping System is a dataset containing locations of and 

information about gas transmission and hazardous liquid pipelines and liquefied natural 

gas plants which are under the jurisdiction of PHMSA. The data are used by PHMSA for 

emergency response, pipeline inspections, regulatory management and compliance, and 

analysis purposes. 

6181 Fed. Reg. 40757-40765 (June 22, 2016).
Page 34 GAO-17-639 Pipeline Safety

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.62 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.63

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.64

• 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 

 62GAO, Standards for Internal Control in the Federal Government, GAO-14-704G

(Washington, D.C.: September 2014).

63OMB, Updated Principles for Risk Analysis, OMB Memorandum M-07-24 (Washington, 

D.C.: Sept. 19, 2007).

64A 2013 Department of Transportation report found that index risk models, similar to 

PHMSA’s risk model, often use judgmentally determined risk factors and weights, and 

should be validated using data. See Department of Transportation, Pipeline Integrity 

Management: An Evaluation to Help Improve PHMSA’s Oversight Of Performance-Based 

Pipeline Safety Programs (Washington, D.C.: Oct. 31, 2013). 

PHMSA Has Not 

Documented Its Decisions 

or Validated the 

Effectiveness of Its Risk 

Ranking Index Model
Page 35 GAO-17-639 Pipeline Safety

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 
Page 36 GAO-17-639 Pipeline Safety

process remains appropriate and effective.65 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.66

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.67 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 

 65OMB, Management’s Responsibility for Enterprise Risk Management and Internal 

Control, OMB Circular No. A-123 (Washington, D.C.: Jul. 15, 2016).

66GAO-14-704G.

67GAO-14-704G.
Page 37 GAO-17-639 Pipeline Safety

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.

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 datadriven and risk-based safety agency.

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 

Conclusions

Recommendations for 

Executive Action
Page 38 GAO-17-639 Pipeline Safety

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.

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.

Susan A. Fleming

Director, Physical Infrastructure Issues

Agency Comments
Appendix I: Additional Observations on 

Pipeline Materials and Corrosion Prevention 

Technologies

Page 39 GAO-17-639 Pipeline Safety

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.1

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.2 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 

 1

For the purposes of this report, we refer to stakeholders with expertise on pipeline 

materials and corrosion as expert stakeholders. Because broad agreement existed across 

the operators and expert stakeholders for many of these topics and our sample was nongeneralizable, we used indefinite quantifiers to describe the responses where appropriate, 

as defined in our methodology. See appendix II for more information.

2

One of the 16 operators and expert stakeholders we interviewed stated that it did not 

know whether the use of these materials in the United States differed from their use in 

Canada, while 5 of the 16 operators and experts we interviewed said they did not know if 

there were differences between the United States and the European Union.

Appendix I: Additional Observations on 

Pipeline Materials and Corrosion Prevention 

Technologies
Appendix I: Additional Observations on 

Pipeline Materials and Corrosion Prevention 

Technologies

Page 40 GAO-17-639 Pipeline Safety

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.3 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 

 3

A three-layer polyethylene coating is composed of a fusion-bonded coating, an 

intermediate layer of adhesive and outer layer of plastic. 
Appendix I: Additional Observations on 

Pipeline Materials and Corrosion Prevention 

Technologies

Page 41 GAO-17-639 Pipeline Safety

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.
Appendix II: Objectives, Scope and 

Methodology

Page 42 GAO-17-639 Pipeline Safety

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).1 (See table 7.) These 

 1

For the purposes of this report, we refer to stakeholders with expertise on pipeline 

materials and corrosion as expert stakeholders. 

Appendix II: Objectives, Scope and 

Methodology
Appendix II: Objectives, Scope and 

Methodology

Page 43 GAO-17-639 Pipeline Safety

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.2 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.

 2

For the purposes of our review, “professional qualifications” in this case generally means 

a professional engineer designation or Ph.D. in a relevant subject, such as engineering, 

chemistry, metallurgy, or similar. “Professional experience” in this case generally means 

extended employment in a relevant field, firms that provide pipeline materials and 

corrosion prevention services, maintenance or repair, quality control/quality assurance, 

research, or consulting. “Professional position” in this case generally means the 

attainment of a position that would indicate a high level of relevant experience or 

knowledge. 
Appendix II: Objectives, Scope and 

Methodology

Page 44 GAO-17-639 Pipeline Safety

Table 7: Stakeholders with Specialized Expertise Selected for Interviews on Pipeline Materials and Corrosion

Stakeholder Type of Stakeholder Representatives Interviewed Title

Colonial Pipeline Pipeline Operator Josh Stanley Manager, Corrosion Prevention

Dominion Energy Ohio Pipeline Operator Vic Magazine

Brian Moidel

Manager, Gas Operations

Principal Engineer 

Enbridge Pipeline Operator Len Krissa

Len LeBlanc

Supervisor, Pipeline Integrity Engineering 

Corrosion Prevention

Director, Pipeline Integrity 

Assessments/Reliability 

NiSource Pipeline Operator Lee Reynolds Manager of Gas Standards

Pacific Gas and Electric Pipeline Operator David McQuilling Director of Corrosion Engineering and 

Services

Shell Pipeline Pipeline Operator Mike Courville

Virgil Wallace

Operator Qualifications Coordinator Senior 

Integrity Engineer

Southern Star Pipeline Operator Randall Neff

Randy Vandervort

Brett Houtz

Manager, Corrosion Services

Supervisor, Corrosion Services

Senior Technical Specialist, Corrosion 

Services

Williams Companies Pipeline Operator Jared Ellsworth

Justin Reynolds

Manager, Pipeline Safety

Supervisor, Asset Integrity

Alberta Energy 

Regulator

Expert Stakeholder Dave Grzyb Technical Specialist, Pipeline Authorizations

DNV/GL Expert Stakeholder John Beavers Corporate Vice President and Senior 

Principal Engineer

Dynamic Risk Expert Stakeholder Patrick Vieth Senior Vice President of Technical Services

International Corrosion 

Services, Ltd.

Expert Stakeholder Roger King Director

Kiefner and Associates Expert Stakeholder Barry Hindin

Michael Rosenfeld

Senior Principal Engineer

Chief Engineer

MATCOR, Inc. Expert Stakeholder Jeff Didas Senior Corrosion Engineer

Phil Hopkins, Ltd Expert Stakeholder Phil Hopkins President and Pipeline Engineering 

Consultant

Pipeline Research 

Council International 

(PRCI)

Expert Stakeholder Laurie Perry Program Manager, Corrosion and

Underground Storage

Source: GAO. | GAO-17-639
Appendix II: Objectives, Scope and 

Methodology

Page 45 GAO-17-639 Pipeline Safety

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.3 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.4

 3

While we collected information on benefits, limitations and factors affecting cost from 

these interviews, we did not review cost-benefit analyses or conduct a formal cost-benefit 

analysis due to a lack of available data. In addition, while we asked operators and expert 

stakeholders about the cost of materials and corrosion prevention technologies during our 

interviews with them, a majority of them stated that they could not provide specific 

estimates for materials and technologies, in part, because they depend on a variety of 

factors. As result, we reported on factors affecting the cost of these materials and 

technologies, rather than specific cost estimates. 

4

We also used this same approach to obtain perspectives on (1) the international use of 

materials and corrosion prevention technologies and (2) potential improvements in 

materials and corrosion prevention technologies, as detailed in appendix I.
Appendix II: Objectives, Scope and 

Methodology

Page 46 GAO-17-639 Pipeline Safety

Table 8: Indefinite Quantifiers Used to Describe Frequency of Operator and Expert 

Stakeholder Views on Pipeline Materials and Corrosion Prevention Technologies

Indefinite quantifier Number of operators and expert stakeholders

A Few 2-4

Several 5-7

Half 8

Majority 9-12

Nearly all 13-15

All 16

Source: GAO. | GAO-17-639

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 
Appendix II: Objectives, Scope and 

Methodology

Page 47 GAO-17-639 Pipeline Safety

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 

Government5

, criteria for risk analysis developed by the Office of 

Management and Budget (OMB),6 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.7

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.

 5

GAO, Standards for Internal Control in the Federal Government, GAO-14-704G

(Washington, D.C.: Sept. 10, 2014).

6

OMB, Updated Principles for Risk Analysis, OMB-M-07-24 (Washington, D.C..: Sept, 19, 

2007); Management’s Responsibility for Enterprise Risk Management and Internal 

Control, OMB Circular No. A-123 (Washington, D.C.: July 15, 2016).

7

Interstate agents are authorized by PHMSA to assist with the inspection of interstate 

pipelines. Of the nine states designated as interstate agents, four states (Connecticut, 

Michigan, Iowa, and Ohio) are designated solely as interstate agents for natural gas, one 

state (Virginia) is designated solely as an interstate agent for hazardous liquids, and four 

states (Arizona, Minnesota, New York and Washington) are designated for both.
Appendix III: Comments from the Department 

of Transportation

Page 48 GAO-17-639 Pipeline Safety

Appendix III: Comments from the 

Department of Transportation
Appendix IV: GAO Contact and Staff 

Acknowledgments

Page 49 GAO-17-639 Pipeline Safety

Susan Fleming, (202) 512-2834 or flemings@gao.gov

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.

Appendix IV: GAO Contact and Staff 

Acknowledgments

GAO Contact

Staff 

Acknowledgments

(101017)
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