GAO

United States General Accounting Office

Report to the Ranking Minority Member,

Committee on Commerce,

House of Representatives

May 2000 PIPELINE SAFETY

The Office of Pipeline

Safety Is Changing

How It Oversees the

Pipeline Industry

GAO/RCED-00-128

Page 1 GAO/RCED-00-128 Oversight of Pipeline Safety

Contents

Letter 3

Appendixes Appendix I: The Bellingham, Washington, Pipeline Accident 40

Appendix II: Maps of Natural Gas Transmission and Hazardous

Liquid Pipelines 47

Appendix III: Status of Risk Management Demonstration Projects 49

Appendix IV: OPS’ Action on Statutory Requirements,

1988-2000 51

Appendix V: GAO Contacts and Staff Acknowledgements 61

Tables Table 1: Relative Occurrence of Transportation Accidents Per

Ton-Mile of Oil Transported, 1992-97 10

Table 2: Milestones for Implementing a Risk Management Approach

for Regulating Large Hazardous Liquid Pipelines 21

Table 3: Transportation Agencies’ Implementation Rates for Safety

Board Recommendations, 1967-99 30

Table 4: Status of Implementation of Statutory Requirements,

1988-2000 34

Table 5: Projects Approved for the Risk Management Demonstration

Program 49

Table 6: Federal Cost of the Risk Management Demonstration

Program, by Fiscal Year 50

Table 7: Pipeline Safety Reauthorization Act of 1988 (P.L. 100-561,

Oct. 31, 1988) 51

Table 8: Oil Pollution Act of 1990 (P.L. 101-380, Aug. 18, 1990) 53

Table 9: Offshore Pipeline Navigational Hazards (P.L. 101-599,

Nov. 16, 1990) 53

Table 10: Pipeline Safety Act of 1992 (P.L. 102-508, Oct. 24, 1992) 55

Table 11: Accountable Pipeline Safety and Partnership Act of 1996

(P.L. 104-304, Oct. 12, 1996) 58

Table 12: Transportation Equity Act for the 21st Century (P.L. 105-178,

June 9, 1998) 60

Figures Figure 1: Components of Natural Gas Transmission and Distribution

Pipelines 7

Figure 2: Number of Pipeline Accidents Resulting In Fatalities,

Injuries, and/or $50,000 or More in Property Damage,

1989-98 11
Contents

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Figure 3: Number of Fatalities and Injuries and Amount of Property

Damage From Pipeline Accidents, 1989-98 13

Figure 4: Number of Major Pipeline Accidents, Miles, and Major

Accidents per 10,000 Miles of Pipeline, 1989-98 15

Figure 5: OPS’ Inspection Activity, by Type of Inspection, 1990-99 24

Figure 6: Warning Letters/Letters of Concern and Fines as

Percentages of Total Enforcement Actions, 1990-98 27

Figure 7: Location of Olympic Pipe Line Rupture 41

Figure 8: Locations of Natural Gas Transmission Pipelines 47

Figure 9: Locations of Hazardous Liquid Pipelines 48

Abbreviations

OPS Office of Pipeline Safety

DOT Department of Transportation
Page 3 GAO/RCED-00-128 Oversight of Pipeline Safety

United States General Accounting Office

Washington, D.C. 20548

Resources, Community, and

Economic Development Division

B-283653 Letr

May 15, 2000

The Honorable John D. Dingell

Ranking Minority Member

Committee on Commerce

House of Representatives

Dear Mr. Dingell:

Pipelines are inherently safer to the public than other modes of freight

transportation for natural gas and hazardous liquids (such as oil products)

because they are, for the most part, located underground. Nevertheless, the

volatile nature of these products means that pipeline accidents can have

serious consequences. For example, when a pipeline ruptured and spilled

about 250,000 gallons of gasoline into a creek in Bellingham, Washington, in

June 1999, three people were killed, eight were injured, several buildings

were damaged, and the banks of the creek were destroyed along a 1.5-mile

section.

The Office of Pipeline Safety, within the Department of Transportation,

administers the national regulatory program to ensure the safe

transportation of natural gas and hazardous liquids by pipeline. The Office

has traditionally carried out its responsibility by issuing minimum

standards and enforcing them uniformly across these pipelines. The

Accountable Pipeline Safety and Partnership Act of 1996 directed the

Office to establish a demonstration program to test a risk management

approach to pipeline safety. This approach involves identifying and

addressing specific risks faced by individual pipeline companies rather

than applying uniform standards regardless of risks. The act allowed the

Office to exempt companies in the program from the uniform standards but

did not eliminate the standards.

Concerned about the recent accident in Bellingham, you asked us to review

the Office’s performance in regulating pipeline safety. Accordingly, we

examined (1) the extent of major pipeline accidents from 1989 through

1998 (the most recent data available), (2) the Office’s implementation of the

1996 act’s risk management demonstration program, (3) the Office’s

inspection and enforcement efforts since the act’s implementation, and

(4) the Office’s responsiveness to recommendations from the National

Transportation Safety Board (the Safety Board) and to statutory
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requirements designed to improve pipeline safety. In addition, you asked us

to provide information on the current status of the investigation of the

accident in Bellingham. This latter information is provided in appendix I.

Results in Brief From 1989 through 1998, pipeline accidents resulted in an average of about

22 fatalities per year. Fatalities from pipeline accidents are relatively low

when compared with those from accidents involving other forms of freight

transportation: On average, about 66 people die each year from barge

accidents, about 590 from railroad accidents, and about 5,100 from truck

accidents. While these statistics provide an indication of the relative safety

of pipelines for transporting natural gas and hazardous liquids, the total

number of major pipeline accidents (those resulting in a fatality, an injury,

or property damage of $50,000 or more) increased by about 4 percent

annually over this 10-year period. Most fatalities and injuries occurred as a

result of accidents on pipelines that transport natural gas to homes and

businesses (primarily intrastate pipelines), while most property damage

occurred as a result of accidents on pipelines transporting hazardous

liquids (primarily interstate pipelines). Furthermore, pipelines that

transport hazardous liquids account for nearly eight times as many major

accidents per mile of pipeline as do pipelines that transport natural gas to

homes and businesses. The Office of Pipeline Safety’s data on the causes of

pipeline accidents are limited to a few categories, but these limited data

indicate that damage from outside forces, such as excavation, is the

primary cause of such accidents.

The Office has implemented a risk management demonstration program, as

the 1996 act requires, and has approved six demonstration projects, which

are ongoing. The Office issued guidance on performance measures for the

overall program and for individual projects but has not established specific

measures of the program’s impact on safety, as the act requires. Even

though the projects are not complete and their safety benefits have not

been quantified, the Office is moving ahead with a risk-based approach to

safety regulation based partially on preliminary qualitative results of the

program. Specifically, the Office has proposed a rule that would require

some companies that operate hazardous liquid pipelines that run through

high-risk areas (populated areas, environmentally sensitive areas, and

commercially navigable waterways) to implement a program to

comprehensively examine pipelines in these areas to identify and address

potential risks, including assessing the current condition of their pipelines.

The proposed rule will supplement, not replace, the existing minimum

standards. The Office also plans to take several actions that are necessary
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to implement the new approach, such as devising a method to review the

companies’ programs and hiring and training additional staff to conduct the

reviews. Office officials estimate that pipeline companies will develop

plans for assessing the condition of their pipelines by September 2001 and

that the assessments will be complete by September 2007. While we agree

that a risk management approach offers the potential to improve pipeline

safety, several critical steps—such as issuing a final rule and hiring staff—

must be completed before the Office can implement such an approach.

Since the act’s implementation, the Office has modified its inspection and

enforcement approach. With respect to inspections, it has moved toward

inspecting entire pipelines rather than segments of pipelines. Since 1996,

the Office has decreased its use of “unit” inspections—inspections of

individual pipeline segments—and has begun inspecting companies’ entire

pipeline operating systems at one time to provide more comprehensive

assessments of safety risks. As a result, the Office has reduced its reliance

on states to inspect interstate pipelines because it is difficult to coordinate

participation by individual states in systemwide inspections. However,

state pipeline safety officials who currently inspect interstate pipelines for

the Office are concerned that their diminishing role has resulted in fewer

and less thorough inspections of pipelines. The Office has also revised its

enforcement of compliance with regulations by reducing its use of fines

and, instead, working with operators to identify and correct safety

problems. From 1990 to 1998, the Office decreased the proportion of

enforcement actions in which it proposed fines from about 49 percent to

about 4 percent. Some state safety regulators agree with this strategy;

others do not. We are recommending that the Secretary of Transportation

direct the Office to work with states to determine how state inspectors

could be used to more effectively oversee pipeline safety and evaluate the

effectiveness of its strategy of reducing the use of fines.

The Office’s responsiveness to the Safety Board’s recommendations and

statutory requirements has been mixed. The Office has historically had the

lowest rate of implementation for these recommendations of any

transportation agency and has not implemented 22 statutory requirements,

12 of which date from 1992 or earlier. It has not implemented some of the

recommendations and requirements because it believes they would be too

costly for the pipeline industry compared with the expected benefits.

However, according to the Safety Board, some of the Office’s analyses of

costs and benefits are flawed because the Office did not consider all of the

benefits. The Office has recently taken action on some issues covered by

outstanding recommendations and requirements, such as identifying
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countermeasures for preventing damage to pipelines from excavation and

requiring pipeline operators to inspect their pipelines for corrosion. Safety

Board officials say they are encouraged by these recent efforts but note

that some of the Office’s actions are incomplete and may not fully address

the Safety Board’s recommendations.

Background Pipelines transport the bulk of natural gas and hazardous liquids (such as

oil products) in the United States.1 Specifically, pipelines carry nearly all of

the natural gas and about 65 percent of the crude oil and refined oil

products. Three primary types of pipelines form a network of nearly

2.2 million miles.

• Natural gas transmission pipelines transport natural gas over long

distances from sources to communities. These pipelines—about

325,000 miles—are primarily interstate.

• Natural gas distribution pipelines continue to transport natural gas from

transmission pipelines to residential, commercial, and industrial

customers. These pipelines—about 1.7 million miles—are primarily

intrastate.

• Hazardous liquid pipelines transport crude oil to refineries and continue

to transport the refined oil product, such as gasoline, to product

terminals and airports. These pipelines—about 156,000 miles—are

primarily interstate.

In addition, pipelines include several components that aid in the collection

and transportation of products. (See fig. 1.) For example, gathering

pipelines collect natural gas or crude oil from producing wells and carry

the product to a natural gas transmission or hazardous liquid pipeline.2

Compressor stations (for gas) and pumping stations (for liquids) keep the

product flowing smoothly.

1

Hazardous liquid pipelines carry products such as crude oil, diesel fuel, gasoline, jet fuel,

anhydrous ammonia, and carbon dioxide.

2

Some gathering lines and segments of gathering lines in rural areas are excluded from

federal pipeline safety regulation. The Office is developing a definition of natural gas

gathering lines that may result in the regulation of some rural gathering lines. The mileage

statistics above include gathering lines that are subject to federal regulation.
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Figure 1: Components of Natural Gas Transmission and Distribution Pipelines

Source: Office of Pipeline Safety.

Natural gas producing wells

Gathering pipelines Transmission pipeline

Processing

plant

Compressor

stations

Underground

storage

Large volume

customer

Regulator

Meter

City

gate

Liquid natural gas plant

Distribution pipelines
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The extensive network of natural gas transmission and hazardous liquid

pipelines appears in appendix II.3

Several federal and state agencies have roles in pipeline safety. The Office

of Pipeline Safety (OPS) develops, issues, and enforces pipeline safety

regulations for natural gas and hazardous liquid pipelines. These

regulations contain minimum safety standards that the pipeline companies

that transport these products must meet for the design, construction,

inspection, testing, operation, and maintenance of pipelines. OPS’ fiscal

year 2000 budget is about $37 million, funded primarily from industry user

fees. In fiscal year 1999, OPS employed 105 people, 51 of whom were

pipeline inspectors.

In general, OPS retains full responsibility for inspecting and enforcing

regulations on interstate pipelines but certifies states to perform these

functions for intrastate pipelines. Certified states are allowed to impose

safety requirements for intrastate pipelines that are stricter than the federal

regulations. As of March 2000, 47 state agencies, the District of Columbia,

and Puerto Rico were certified for intrastate natural gas pipeline

inspections, and 12 state agencies were certified for intrastate hazardous

liquid pipeline inspections.4 Certified states are authorized to receive

reimbursement of up to 50 percent of the costs of their pipeline safety

programs from OPS. In fiscal year 1999, these states received about

$13 million from OPS in state pipeline safety grants, or an average of about

44 percent of their estimated budgets. In fiscal year 1998, the states

employed about 300 pipeline inspectors.

OPS also uses some states to help inspect interstate pipelines. These states,

or “interstate agents,” inspect segments of interstate pipelines within their

boundaries. However, OPS handles any enforcement actions identified

through inspections conducted by these interstate agents. As of March

2000, eight states were acting as interstate agents—five states for natural

gas pipelines, one state for hazardous liquid pipelines, and two states for

both types of pipelines. These states do not receive additional federal funds

for inspecting interstate pipelines.

3

No map is available for the natural gas distribution pipeline network, which is too extensive

to map because it is located in populated areas.

4

In addition, four state agencies—Delaware for natural gas and Kentucky, New Mexico, and

South Carolina for hazardous liquid—have agreements with OPS to inspect intrastate

pipelines, but OPS handles any enforcement actions.
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Other federal agencies, such as the Minerals Management Service within

the Department of the Interior and the Environmental Protection Agency,

also have some regulatory authority related to pipeline safety. The Minerals

Management Service has jurisdiction over producer-operated oil pipelines

on the Outer Continental Shelf. The Environmental Protection Agency

regulates tanks used to store hazardous liquids or transfer them to or from

other modes of transportation. In contrast, OPS regulates storage tanks

used to store hazardous liquids for continued transportation by pipeline at

a later date or to relieve surges in the pipeline system. A single storage tank

or a facility with multiple tanks may have uses that fall under the authority

of both the Environmental Protection Agency and OPS. As of April 2000,

the agencies were working to clarify the circumstances under which each

agency has authority.

The National Transportation Safety Board investigates transportation

accidents, including significant pipeline accidents (such as those involving

fatalities). On the basis of these investigations, the Safety Board issues

recommendations to OPS and other federal agencies aimed at preventing

future accidents. Finally, several federal statutes enacted since 1988

contain requirements designed to improve pipeline safety and enhance

OPS’ ability to oversee the pipeline industry. Many of these requirements

address the same issues as the Safety Board’s recommendations.

Pipelines Are

Relatively Safe, but the

Number of Major

Accidents Increased

From 1989 Through

1998

Pipelines have an inherent safety advantage over other modes of freight

transportation because they are primarily located underground, away from

public contact. From 1989 through 1998, pipeline accidents resulted in an

average of about 22 fatalities per year, compared with about 66 from barge

accidents, about 590 from railroad accidents, and about 5,100 from large

truck accidents.5 A 1999 study comparing modes of oil transportation from

1992 through 1997—pipeline, rail, tank ship, barge, and truck—found that

the likelihood of fatality, injury, or fire and/or explosion is generally lowest

for pipelines.6 The rate of fatalities, injuries, and fires/explosions per tonmile of oil transported for all other modes is typically at least twice—and in

5

In its regulations, OPS refers to the release of natural gas from a pipeline as an “incident”

and a spill from a hazardous liquid pipeline as an “accident.” For simplicity, this report will

refer to both as “accidents.”

6

Cheryl J. Trench, The U.S. Oil Pipeline Industry’s Safety Performance, Allegro Energy

Group report prepared for the Association of Oil Pipelines and the American Petroleum

Institute (May 1999) (Rev.).
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some cases more than 10 times—as great as the rate for pipelines. (See

table 1.)

Table 1: Relative Occurrence of Transportation Accidents Per Ton-Mile of Oil

Transported, 1992-97

a

The rates of occurrence are based on a value of 1.0 for pipeline. Values of less than 1.0 indicate a

better safety record.

Source: Association of Oil Pipelines.

While pipelines are relatively safe compared with other transportation

modes, the number of major pipeline accidents increased overall from 1989

through 1998.7 In total, there were 2,241 major accidents (those causing a

fatality, an injury, or more than $50,000 in property damage) during this

period. Although the number of major accidents varied from year to year,

these accidents increased by approximately 4 percent annually. 8 (See

fig. 2.) According to OPS officials, the increase in major accidents over this

period can be attributed to a 10-percent overall increase in pipeline

mileage, growth in the volume of products transported by pipelines (due to

an increase in the nation’s energy consumption), and population growth

near pipelines.

Event Pipelinea Rail Tank ship Barge Truck

Fatality 1.0 2.7 4.0 10.2 87.3

Injury 1.0 2.6 0.7 0.9 2.3

Fire/explosion 1.0 8.6 1.2 4.0 34.7

7

All natural gas and hazardous liquid pipeline operators are required to report accidents that

result in a fatality, an injury, or $50,000 or more in property damage (which this report

defines as “major”). In addition, natural gas pipeline operators are required to report events

that result in an emergency shutdown of a liquefied natural gas facility and may report any

accident they consider “significant,” even if it does not meet any reporting threshold.

Furthermore, hazardous liquid operators are required to report any accident that results in

an explosion or a fire, the release of 50 or more barrels of hazardous liquid or carbon

dioxide, or the escape into the atmosphere of more than 5 barrels per day of highly volatile

liquids. There were 1,801 accidents from 1989 through 1998 that did not meet the definition

of a major accident.

8

The total number of accidents, major and nonmajor, reported to OPS decreased by about

1.5 percent annually over this period.
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Figure 2: Number of Pipeline Accidents Resulting In Fatalities, Injuries, and/or

$50,000 or More in Property Damage, 1989-98

Source: GAO’s analysis of OPS’ data.

From 1989 through 1998, 226 people died and 1,030 people were injured in

major pipeline accidents.9 (See fig. 3.) Accidents on natural gas distribution

pipelines (which are primarily intrastate) accounted for 173—or

77 percent—of the fatalities and 743—or 72 percent—of the injuries from

1989 through 1998. Because these pipelines are primarily located in

populous areas, it is not surprising that accidents on them affect humans

more than accidents on other types of pipelines. In addition, major pipeline

accidents caused about $700 million in property damage. From 1989

through 1998, hazardous liquid pipelines (which are primarily interstate)

accounted for about $350 million, or 50 percent, of this property damage

9

This figure does not include the injuries that occurred during one series of accidents

caused by severe flooding near Houston, Texas, in Oct. 1994. We excluded these injuries

because OPS’ and the Safety Board’s data disagree on the number of people injured. OPS’

data indicate 1,851 injuries, while the Safety Board reported that a total of 547 persons were

treated, primarily for smoke and vapor inhalation. We also excluded this accident from our

analysis because we could not determine to what extent the injuries were the result of

explosions of petroleum and petroleum products released from the ruptured pipelines or of

the controlled burn of these products by the spill response team.

0

50

100

150

200

250

300

1989 1990 1991 1992 1993 1994 1995 1996 1997 1998
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because the liquids do not dissipate into the atmosphere, as does natural

gas.
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Figure 3: Number of Fatalities and Injuries and Amount of Property Damage From Pipeline Accidents, 1989-98

Source: GAO’s analysis of OPS’ data.

0

20

40

60

80

100

120

140

160

180

Natural gas

distribution

Natural gas

transmission

Hazardous

liquid

Fatalities

0

100

200

300

400

500

600

700

800

Natural gas

distribution

Natural gas

transmission

Hazardous

liquid

Injuries

$0

$50

$100

$150

$200

$250

$300

$350

Natural gas

distribution

Natural gas

transmission

Hazardous

liquid

Property Damage

Dollars in millions
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Representatives from environmental groups believe that property damage

from pipeline accidents is understated because not all damage to the

environment may be reported to OPS by pipeline operators. For example,

over 1.5 million barrels of hazardous liquids—primarily crude oil and

gasoline—were spilled from pipelines as a result of all pipeline accidents

reported to OPS. However, the total amount spilled from pipelines and,

thus, the environmental damage, is actually greater because OPS does not

require pipeline operators to report spills of less than 50 barrels. Although

there is no complete source of information on these smaller spills, the

Environmental Protection Agency maintains data on oil pipeline spills in

areas where such spills could cause pollution to navigable waters. These

data show that more than 16,000 spills of less than 50 barrels occurred from

1989 through 1998.

Of the major pipeline accidents occurring from 1989 through 1998, most—

about 43 percent—occurred on natural gas distribution pipelines. These

pipelines also account for the majority of pipeline mileage. However,

hazardous liquid pipelines, which account for the smallest portion of total

pipeline mileage, have nearly eight times as many major accidents per mile

of pipeline as do natural gas distribution pipelines. (See fig. 4.)
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Figure 4: Number of Major Pipeline Accidents, Miles, and Major Accidents per 10,000 Miles of Pipeline, 1989-98

Source: GAO’s analysis of OPS’ data.

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

1,800,000

Natural gas

distribution

Natural gas

transmission

Hazardous

liquid

0

5

10

15

20

25

30

35

40

45

Natural gas

distribution

Natural gas

transmission

Hazardous

liquid

0

100

200

300

400

500

600

700

800

900

1,000

Natural gas

distribution

Natural gas

transmission

Hazardous

liquid

Number of major accidents per

10,000 miles of pipeline

Number of major pipeline accidents Number of pipeline miles
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OPS does not collect comprehensive information on the causes of pipeline

accidents. However, OPS’ available data indicate that the primary cause of

pipeline accidents from 1989 through 1998 was damage from external

forces, such as an outside party digging near a pipeline or a natural force

like an earthquake or a landslide. These data are limited because OPS uses

only five categories of causes for accidents on natural gas distribution

pipelines, four categories for those on natural gas transmission pipelines,

and seven categories for those on hazardous liquid pipelines. As a result, a

large proportion of accidents are attributed to “other causes” that range

from failed gaskets or seals to faulty valves. According to these data, from

1989 through 1998, the three most prevalent causes of pipeline accidents

were damage from outside forces (45 percent), “other” (25 percent), and

corrosion of the pipe (15 percent).

Although Benefits of

Demonstration

Program Have Not

Been Quantified, OPS

Is Moving Ahead With a

New Regulatory

Approach

As a result of the Accountable Pipeline Safety and Partnership Act of 1996,

OPS has implemented a risk management demonstration program to

investigate whether formalized risk management programs for individual

pipeline companies can provide an alternative to the current regulatory

approach and achieve a superior level of safety and environmental

protection.10 However, OPS has not established performance measures for

the program’s impact on safety, as required by the act. OPS maintains that

the ongoing program has already produced some qualitative improvements,

such as directing resources to the areas posing the greatest safety risks.

Partially as a result of its experience with the demonstration program, OPS

has proposed a rule that would require some companies that operate

hazardous liquid pipelines that run through populated areas,

environmentally sensitive areas, or commercially navigable waterways to

implement a program to comprehensively examine pipelines in these areas

to identify and address potential risks.

10The act also required, among other things, that OPS conduct risk assessments when

prescribing new regulations. In addition to identifying the costs and benefits of the new

regulation, OPS must identify the regulatory and nonregulatory options considered, explain

its reasons for choosing the selected option instead of the others, and identify the

information on which the risk assessment and selected option are based. The status of OPS’

actions on these additional requirements is included in app. IV.
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Risk Management

Demonstration Program

Was Designed to Show

Benefits of Going Beyond

Minimum Regulatory

Standards

The 1996 act, together with a presidential memorandum to the Secretary of

Transportation, requires OPS to evaluate, through a demonstration

program, whether a risk management approach to pipeline safety can

achieve a level of safety and environmental protection that is greater than

the level achievable through compliance with the current pipeline safety

regulations.11 The current regulations establish minimum safety

requirements for all pipeline companies, such as a requirement for a

protective coating on all pipelines to mitigate corrosion. A risk

management approach goes beyond the minimum requirements by

identifying and focusing resources on risks to individual pipelines that may

not be fully addressed in the regulations. For example, identifying

emergency response capability as a risk and subsequently developing an

electronic system that would notify emergency officials of a pipeline leak

or rupture would exceed current regulations.

The act further required OPS to develop performance measures for the

program to evaluate its safety and environmental benefits. The act also

authorized OPS to exempt companies participating in these projects from

all or a portion of the existing regulations.12 Finally, the act required OPS to

report by March 31, 2000, on the results of the demonstration program,

including its safety and environmental benefits.

To address the requirement for demonstrating an improved level of safety

and environmental benefits, OPS issued guidance that identified superior

safety, environmental protection, and service reliability as one of three

primary objectives for the program. The guidance also identified increased

efficiency of pipeline operations and improved communication among

industry, government, and other stakeholders as two additional primary

objectives. To measure progress toward these objectives, the guidance

11The 1996 act contained no limitation on the number of demonstration projects and

required that risk management plans be designed to achieve a level of safety equivalent to or

greater than the level that would otherwise be achieved. However, when signing the 1996

act, the President directed the Secretary of Transportation to limit the number of projects to

10 and to ensure that the projects demonstrate superior, not just equal, safety and

environmental benefits.

12One company that operates a natural gas pipeline has received an exemption from the

current regulations. If the population density increases near a pipeline, the current

regulations require the pipeline company to install a thicker-walled pipe or reduce the

operating pressure. In exchange for the exemption from this requirement, OPS is requiring

the company to take additional precautions, such as conducting internal inspections of the

pipelines in these areas, while maintaining the existing pipe at the original pressure.
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describes potential programwide measures, such as accident data, risk

awareness, and customer service. The guidance also recognizes the need

for project-specific measures intended to document starting conditions,

changes during the program, and expected outcomes for each project.

According to the guidance, the project-specific measures were to be

developed by the pipeline operators before the projects were approved by

OPS.

As of January 2000, OPS had approved six projects for the program. The

projects vary in scope, ranging from examining the risks associated with

excavation work on a single pipeline at one company, to a comprehensive

risk management plan designed to assess all risks associated with the

operation of two multistate pipeline systems owned by another company.

(App. III provides more details on the individual projects and the program’s

overall costs.)

OPS Has Not Measured

Benefits of Risk

Management Demonstration

Program

OPS has not complied with the act’s requirements or its own guidance on

developing performance measures for the risk management demonstration

program. Specifically, OPS has not developed programwide measures and

has approved five of the six demonstration projects without projectspecific measures in place, even though OPS’ guidance required pipeline

operators to develop such measures before the agency would approve a

project. OPS officials and representatives of participating companies told

us that they have been unable to develop performance measures because

the impact on safety cannot easily be isolated from the effects of other

safety activities outside the program, especially given the relatively short

duration of the program. For example, an increase in the number of defects

found over a period of years may indicate a growing risk of pipeline failure,

or it may reflect the results of targeting inspections to identify weaknesses

or of introducing new technologies to detect defects. In addition, OPS

officials told us that the measures have been difficult to develop because

the participating companies have unique pipeline systems and the

demonstration projects involve different aspects of the systems. Moreover,

according to the officials, many companies are not collecting the types of

data necessary to support an evaluation of the program’s overall impact on

safety.

Only one program participant, Philips Pipe Line, has developed

performance measures and generated data for its project. According to

OPS officials, this project is limited in scope and has thus far generated
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little data. The other participants are trying to develop performance

measures for their projects.

While OPS has not developed any programwide or project-specific

measures to evaluate the program’s performance, OPS officials told us that

the program has yielded many qualitative benefits related to its three

objectives. For example, each company is performing safety activities that

exceed the requirements in the current regulations, such as conducting

periodic internal inspections of pipelines and installing additional valves to

prevent hazardous liquids from flowing into rivers. Officials with one

company said that the company has allocated its resources more

effectively by using a risk-based computer model to develop funding

priorities for its valve modification and replacement efforts. To improve

communication and information flow, two companies have conducted

“hands-on” workshops for OPS, and another company is developing a

computerized method of exchanging information with OPS.

Although the act required OPS to issue a report on the results of the

demonstration program in March 2000, OPS plans to issue a report in

spring 2000 on the progress of the program. OPS officials do not know

when the program will be complete. According to OPS officials, the

projects took longer to implement than planned because, among other

things, (1) the participating companies did not already have vigorous,

formalized risk management programs in place; (2) OPS took longer than

expected to review and approve individual projects; and (3) several of the

applicant companies underwent corporate mergers that created

uncertainties about whether the companies would continue to participate

in the program.
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OPS Is Moving to Implement

Risk Management Into Its

Regulatory Framework

Even though the demonstration program is still ongoing and its safety and

environmental benefits have not yet been quantified, OPS has proposed a

rule that draws, in part, on the agency’s experiences with the

demonstration program to incorporate the use of a risk management

approach in pipeline safety regulations.13 The proposed rule would affect

hazardous liquid pipeline companies (companies that operate systems of

500 miles or more) that have pipelines in “high-consequence areas.” The

rule defines these areas as populated areas, environmentally sensitive

areas, or commercially navigable waterways.14 OPS estimates that the rule

would apply to 66 pipeline companies that operate about 87 percent of the

nation’s hazardous liquid pipeline mileage. All pipeline operators would

still be required to follow the current minimum regulations.

Companies affected by this rule would be required to develop an “integrity

management program” to comprehensively examine pipelines in highconsequence areas to identify and address potential risks. Such a program

would include, among other things, (1) a plan for assessing the condition of

pipelines in these areas, (2) periodic reassessments of the pipelines,

(3) criteria for repairing deficiencies discovered through the assessments,

and (4) measures of the program’s effectiveness. Methods to assess the

condition of the pipelines include internal inspections using “smart pigs”

(devices that can travel through the pipelines to detect flaws) and

hydrostatic testing (draining the pipeline, filling it with water, and

increasing the pressure within the pipeline to identify weak points).

OPS intends to review companies’ integrity management programs,

including the risks identified by the companies and their strategies for

addressing the risks. Although OPS officials have not determined exactly

how these reviews will be integrated into the agency’s periodic inspections

of pipeline companies, they told us the reviews would require additional

personnel. OPS officials could not estimate how many additional staff

would eventually be needed. The agency has requested four additional staff

13The proposed rule also draws on the agency’s experiences in inspecting pipeline

companies’ entire operating systems (described in the next section), investigating accidents,

and conducting system integrity initiatives.

14According to OPS officials, the initial rule would affect operators of large hazardous liquid

pipeline systems because OPS has gained familiarity with their operations through the risk

management demonstration program. Subsequent rules would affect operators of small

hazardous liquid pipelines and natural gas transmission pipelines in high-consequence

areas.
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for fiscal year 2001, and OPS officials expect to request more in future

years. In addition, agency officials told us that OPS is considering hiring

contractors to assist with these reviews.

Several actions must occur before OPS can fully implement this new

approach to regulating pipeline safety. OPS issued a proposed rule on

April 24, 2000, and must incorporate comments from the industry and the

public in a final rule. OPS must also complete another rule on the definition

of areas that are unusually sensitive to environmental damage before it can

identify high-consequence areas.15 In addition, OPS must develop

guidelines for reviewing companies’ integrity management programs and

hire and train the additional staff needed to conduct the reviews.

Meanwhile, the companies that have pipelines in high-consequence areas

must develop their programs and assess the current condition of their

pipelines. OPS estimates that pipeline companies will develop plans for

assessing the condition of their pipelines by September 2001 and that the

assessments will be complete by September 2007. (See table 2.)

Table 2: Milestones for Implementing a Risk Management Approach for Regulating

Large Hazardous Liquid Pipelines

Source: GAO’s analysis of OPS’ data.

15OPS issued a proposed rule on the definition of areas unusually sensitive to environmental

damage on Dec. 30, 1999. Comments on the proposed rule are due by June 27, 2000.

Date Action

April 2000 OPS issued a proposed rule requiring enhanced protection of

high-consequence areas

October 2000 OPS issues the final rule

Beginning October 2000 OPS hires and trains additional staff to review companies’

integrity management programs

December 2000 OPS completes the final rule on the definition of areas

unusually sensitive to environmental damage and makes

mapping information available to pipeline companies on the

Internet

September 2001 Pipeline companies complete plans for assessing the

condition of pipelines

September 2004 Individual companies’ assessments are 50 percent complete

September 2007 Assessments are 100 percent complete
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While we agree that a risk management approach offers the potential to

improve pipeline safety, we believe that OPS’ proposed rule to broadly

implement it is not supported by quantifiable evidence (intended to be

obtained through the demonstration program) that such an approach has

led—or could lead—to a higher level of safety and environmental

protection. In addition, OPS plans to require performance measures for

pipeline companies’ integrity management programs, even though OPS and

pipeline operators were not able to develop such measures for the risk

management demonstration program. Nevertheless, the rulemaking

process could give the safety community, the regulated industry, and

affected states and communities the opportunity to shape the final rule so

as to establish evidence of the approach’s impact on safety and provide for

reporting on outcomes and periodic assessments of its effectiveness.

OPS Is Changing How

It Inspects Pipelines

and Enforces

Compliance With

Regulations

OPS is moving toward inspecting entire pipelines rather than segments of

pipelines and is reducing its reliance on fines to enforce compliance with

its regulations. Since 1996, OPS has conducted 10 “systemwide

inspections” to identify safety risks to companies’ entire pipeline systems.

These inspections require more time and resources per inspection than

OPS’ traditional approach, which is based on inspecting segments or

“units” of pipelines. Partly because it was emphasizing systemwide

inspections, OPS reduced the number of unit inspections by 47 percent

from 1996 through 1999. Also as a result of systemwide inspections, OPS

has decreased its reliance on state regulators to inspect interstate pipelines

because the agency prefers to use a team of federal inspectors to conduct

the systemwide inspections rather than coordinate the activities of federal

inspectors and inspectors from multiple states. However, some state

regulators are concerned that their diminishing role has resulted in fewer

and less thorough inspections.

For enforcement, OPS has been decreasing its use of fines for pipeline

companies’ violations of safety regulations since before the 1996 act. From

1990 through 1998, OPS’ use of fines decreased from 49 percent of total

enforcement actions to 4 percent. According to OPS officials, this strategy

allows them to focus their efforts and the companies’ resources on

correcting problems, but they have not evaluated whether their reduced

reliance on fines is effective in achieving compliance with regulations.
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OPS Is Changing Its

Inspection Approach to

Focus on Entire Pipeline

Systems

Traditionally, OPS has inspected pipeline companies by conducting “unit

inspections”—a checklist approach verifying that an individual operating

unit of a company’s entire pipeline system is in compliance with pipeline

safety regulations. A unit inspection is generally conducted by one OPS

inspector in about 3 days. Instead of relying primarily on a unit-by-unit

approach to inspections, OPS is now inspecting pipelines through

“systemwide inspections”—reviewing all of a company’s related operating

units at once. Because systemwide inspections can cover hundreds of

miles of pipeline in various regions of the country, OPS uses a team of

inspectors from all OPS regions that contain part of the operator’s system

to inspect all of the operating units. According to OPS officials, a

systemwide inspection is the equivalent of multiple unit inspections. OPS

conducted six systemwide inspections in 1998 and four in 1999; it plans to

conduct eight in 2000.

According to OPS officials, systemwide inspections provide a better

assessment of the potential safety risks to pipelines than do unit

inspections because systemwide inspections can uncover problems that

unit inspections would not identify. For example, according to OPS

officials, one pipeline company did not coordinate its corrosion prevention

activities with information it was obtaining from another part of the

company on external damage. Such damage—e.g., a nick in a pipeline’s

protective coating—can lead to corrosion. During a systemwide inspection,

OPS identified this lack of communication as a potential threat to the

pipeline’s safety.

Besides moving to systemwide inspections, OPS is spending more time on

construction inspections to reduce the risk that defects will be built into

pipelines during construction. Construction inspections also involve more

OPS resources than do unit inspections because months may be needed to

build a pipeline and inspectors must review plans and observe crucial

points in the construction. Since 1995, both the number of pipeline

construction inspections and the time OPS inspectors have spent on such

inspections have increased. In 1999, OPS inspectors spent 546 days on

65 construction inspections, compared with 102 days on 30 inspections in

1995.

As a result of its change in inspection philosophy, OPS is conducting fewer

unit inspections. The number of unit inspections conducted by OPS

decreased by 47 percent from 1996 through 1999. (See fig. 5.) (The number

of inspections increased sharply during 1995 and 1996 because additional

inspectors were hired during that period; since that time, the staffing has
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remained level.) According to OPS officials, this decrease is due to the

increased emphasis on systemwide and construction inspections, as well

as an increase in the number of accident investigations and in the resources

devoted to risk management projects. In addition, OPS officials told us that

each unit inspection now takes more time than it did in the past because

the agency has modified its inspection form to obtain more in-depth

information on how the pipeline company is ensuring the pipeline’s safety.

For example, the new form requires the inspector to evaluate the overall

quality of the operator’s corrosion-control program.

Figure 5: OPS’ Inspection Activity, by Type of Inspection, 1990-99

Note: “Other” includes failure investigations, complaint investigations, and systemwide inspections.

Source: GAO’s analysis of OPS’ data.

0

100

200

300

400

500

600

700

800

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999

Unit

Construction

Other
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Also as a result of its change in inspection philosophy, OPS is relying less

on states to inspect interstate pipelines. Although OPS is responsible for

inspecting these pipelines, it certified some states to act as interstate

agents in the early 1980s because it did not have enough inspection

resources. From 1990 through 1994, about 12 interstate agents conducted

between 20 and 26 percent of all interstate inspections. In 1995 and 1996,

OPS hired additional inspectors and started taking back responsibility for

these inspections. By 1999, only 8 percent of all interstate inspections were

conducted by 10 interstate agents. In December 1999, OPS canceled its

interstate agent agreements with Arizona and Nevada, leaving eight

interstate agents—California, Connecticut, Iowa, Michigan, Minnesota,

New York, Ohio, and West Virginia.16

According to OPS officials, the state agencies have performed well as

interstate agents, but it is difficult to coordinate inspections by interstate

agents—each responsible for the portion of a multistate pipeline system

within its own borders—into a systemwide inspection. Rather than

coordinating the activities of federal and state inspectors, OPS prefers to

use a team of federal inspectors to conduct a systemwide inspection. In

addition, OPS officials told us that devoting less time to their

responsibilities as interstate agents would allow the states to focus their

efforts on intrastate distribution pipelines, where most fatalities from

pipeline accidents occur.

Some state officials do not agree with OPS’ decision to eliminate interstate

agents because they are concerned about its impact on safety. Even though

interstate agents do not receive additional federal funds for inspecting

interstate pipelines, officials from these states prefer to inspect these

pipelines because it allows them to oversee the safety of all pipelines

within their boundaries. Some current and prior interstate agents we

contacted told us that they inspect operators more frequently than OPS—

generally once every year compared with once every 1 to 4 years for OPS—

and spend 2 to 4 times longer performing the inspections than does OPS.

According to these officials, more frequent and more thorough inspections

improve their ability to detect safety problems.

16In Mar. 2000, OPS proposed an agreement with the state of Washington involving the

inspection of interstate pipelines, but, according to OPS officials, the state will not be an

interstate agent.
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In addition, some state officials are concerned that because OPS schedules

all of its inspections in advance, some violations could go undiscovered.

For example, a Connecticut pipeline safety official told us that the state’s

no-notice inspections on intrastate construction projects have discovered

three times as many violations as advance-notice inspections. (According

to an OPS official, OPS notifies the companies of the anticipated date of

inspections so the companies can have the appropriate manuals and

representatives available, but it does not tell the companies which portions

of the pipelines will be examined.)

The Department of Transportation (DOT) has proposed legislation to

reauthorize the pipeline safety program.17 Among other things, this

legislation would increase the ability of states to participate in the

oversight of interstate pipeline transportation (including new construction

inspections or accident investigations) and funding for these activities.

OPS Is Decreasing the Use

of Fines for Violations

Since 1990, OPS has decreased its use of fines and increased its use of less

severe corrective actions. According to OPS officials, this strategy allows

them to work more constructively with companies to address problems.

For example, instead of issuing a fine, OPS required a pipeline operator to

hydrostatically test 350 miles of pipeline following an accident in 1993. The

test revealed seven additional areas that were susceptible to future leaks.

Fines are reserved for severe violations, such as those that have resulted in

fatalities or substantial environmental damage, or for failures to address

problems previously identified by OPS. OPS has not assessed the impact of

this approach on safety.

The number of enforcement actions OPS has taken increased from 94 in

1990 to 218 in 1998—a 132-percent increase. However, OPS has also

decreased the proportion of enforcement actions in which it proposed fines

from about 49 percent in 1990 to about 4 percent in 1998. During this time,

it increased the proportion of warning letters and letters of concern that

are used to inform pipeline companies of probable violations of safety

regulations or other pipeline safety risks but do not assess a fine. The

proportion of enforcement actions in which these letters were sent

increased from about 33 percent in 1990 to about 68 percent in 1998. (See

fig. 6.)

17The Pipeline Safety and Community Protection Act of 2000 was introduced in the Senate

on Apr. 12, 2000 (S. 2409) and the House on Apr. 13, 2000 (H.R. 4276).
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Figure 6: Warning Letters/Letters of Concern and Fines as Percentages of Total Enforcement Actions, 1990-98

Note: The percentages for letters and fines do not add to 100 percent because OPS also uses other

enforcement actions, such as compliance orders, to specify the actions a company must take to

correct a violation. In addition, an enforcement action may include multiple actions, such as a fine and

a compliance order.

Source: GAO’s analysis of OPS’ data.

According to OPS officials, the proportion of warning letters and letters of

concern has increased because letters are now used to inform companies

not only of compliance problems, but also of “best practices” that OPS

believes would improve the safety of the companies’ pipelines. These

officials told us that the agency also relies heavily on other enforcement

actions that do not involve fines, such as compliance orders requiring

pipeline companies to take action to correct safety violations. However,

OPS officials were not able to identify (1) how many letters addressed “best

practices” rather than safety violations and (2) how many other

enforcement actions did not involve fines.

OPS has not assessed the effectiveness of its reduced reliance on fines.

However, OPS reported in 1997 that some other federal agencies—

including the Federal Railroad Administration, the Federal Aviation

0

10

20

30

40

50

60

70

1990

Percent

1991 1992 1993 1994 1995 1996 1997 1998

Warning letters/letters of concern

Fines
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Administration, and the Occupational Safety and Health Administration—

share OPS’ philosophy concerning the use of fines. For example, the report

noted that the Federal Railroad Administration generally gives a rail carrier

the opportunity to correct a safety problem before formally citing the

carrier for violations and suspends proposed penalties in return for the

carrier’s agreeing to take immediate corrective action. The report did not

assess the extent to which federal agencies that agree with OPS’ approach

have reduced their reliance on fines.

While some state pipeline regulators share OPS’ enforcement approach for

the intrastate pipelines under their jurisdiction, others continue to use fines

extensively as a deterrent to noncompliance. For example, a Michigan

official told us that Michigan pipeline safety regulators typically do not

impose fines. In 1998, the state imposed no fines, and in 1999, it imposed

only three of about $1,000 each. According to the Michigan official,

Michigan regulators have always believed that civil penalties are not a

strong deterrent to noncompliance and the few fines that Michigan does

impose are for more serious violations. In contrast, Ohio pipeline safety

regulators believe fines are an effective enforcement tool. According to one

Ohio pipeline safety official, over the past 7-8 years, Ohio has imposed an

average of one fine per year for approximately $50,000. In Ohio, the amount

of the civil penalty depends on the seriousness of the violation and the size

of the operator, and the penalties have ranged from $300 to $125,000.

OPS’ Responsiveness

to the Safety Board’s

Recommendations and

to Statutory

Requirements Has

Been Mixed

OPS has a mixed record in responding to the Safety Board’s

recommendations. Historically, it has had the lowest rate of any

transportation agency for implementing these recommendations. Some of

the recommendations that OPS has not fully implemented have dealt with

issues that the Safety Board has repeatedly reported on, such as the use of

safety valves to rapidly shut down pipelines after ruptures and periodic

internal inspections of pipelines to identify defects. OPS has recently taken

action to improve its responsiveness in several other areas that the Safety

Board has addressed, including excavation damage, corrosion control, and

data quality. While Safety Board officials are encouraged by these recent

efforts, they remain somewhat skeptical of OPS because, in the Safety

Board’s opinion, OPS has not followed through on past promises to

implement the Safety Board’s recommendations.

Several federal statutes also address pipeline safety issues, including a

number of those covered by the Safety Board’s recommendations.

Specifically, since 1988, the Congress has imposed 49 requirements
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designed to improve pipeline safety. OPS has not implemented 22 of these

requirements, 12 of which date from 1992 and prior years.

OPS Has Not Fully

Implemented the Safety

Board’s Recommendations,

but May Be Improving Its

Responsiveness

Since 1967, the Safety Board has made 243 recommendations to OPS in

response to its investigations of significant pipeline accidents (such as

those in which a fatality has occurred). According to the Safety Board, OPS

implemented only 69 percent of these recommendations and has

historically had the lowest response rate of any transportation agency. (See

table 3.) However, because this measure includes data from over 30 years,

it may not accurately reflect OPS’ current efforts to implement the Safety

Board’s recommendations.18

18According to Safety Board officials, a measure to capture an agency’s recent (e.g., within

the last 5 years) efforts would not be meaningful because (1) many of the agency’s actions in

response to the recommendations would probably not be complete and (2) the agency might

not follow through on promises to implement recommendations.
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Table 3: Transportation Agencies’ Implementation Rates for Safety Board

Recommendations, 1967-99

Note: The Research and Special Programs Administration also includes the Office of Hazardous

Materials Safety, which has received 131 recommendations and whose implementation rate was 75

percent from 1967 through 1999.

Source: National Transportation Safety Board.

Many of the Safety Board’s recommendations deal with recurring issues,

such as the use of valves to rapidly shut down pipelines after a rupture, the

need for periodic internal inspections of pipelines, and the need to ensure

that pipeline operators are adequately trained to respond to emergencies.

According to OPS officials, OPS rarely disagrees with the Safety Board on

the issues covered in the recommendations. However, strong differences

exist between the agencies on whether and how to implement the

recommendations, as the following examples show:

• The Safety Board has issued 11 recommendations since 1971 on using

valves to rapidly shut down the flow of product to a ruptured pipeline to

mitigate damage. The Safety Board has recommended that OPS require

the use of excess flow valves—valves that stop the flow of gas on

smaller service lines, such as natural gas distribution lines, when the

flow exceeds a specified amount—on all new single-family residential

high-pressure service lines. In addition, the Safety Board continues to

Transportation agency

Total number of

recommendations

Implementation

rate (percent)

Maritime Administration 17 100

Secretary of the Department of

Transportation 247 88

Federal Highway Administration 446 87

National Highway Traffic Safety

Administration 278 87

Federal Aviation Administration 3,756 83

Federal Transit Administration 66 82

United States Coast Guard 1,162 74

Federal Railroad Administration 483 73

Research and Special Programs

Administration 374 72

Office of Pipeline Safety (within the

Research and Special Programs

Administration) 243 69

Total/average rate 6,829 81
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recommend that OPS require the use of automatic or remotely operated

valves on high-pressure pipelines in urban or environmentally sensitive

areas. OPS has been opposed to requiring the widespread use of valves

because several cost/benefit studies showed that the costs to the

industry of installing valves are generally greater than the expected

benefits. However, according to Safety Board officials, OPS does not

always consider the full range of benefits in its analyses. For example,

OPS concluded that there was no significant benefit from installing

remotely controlled valves on natural gas transmission pipelines

because the gas ignites upon escape and a rapid shutdown would not

prevent fire. However, in March 1994, a rupture on a natural gas

transmission pipeline in Edison, New Jersey, resulted in a fire that

injured 112 people and destroyed eight buildings. Damage from the

accident exceeded $25 million. The Safety Board reported that

operators of the pipeline were unable to shut down the gas flow to the

rupture for 2-1⁄2 hours. Had the operator been able to promptly shut it

down, the Safety Board stated, firefighters could have extinguished the

fire sooner and the damage to the apartment buildings would have been

significantly reduced. The proposed rule on enhanced protection of

pipelines in high-consequence areas would require pipeline companies

to consider the use of remotely operated valves in these areas.

• Three Safety Board recommendations in 1987 called for OPS to require

operators to conduct periodic internal inspections of all pipelines to

identify weaknesses or defects. Although OPS required, in 1994, that

new pipelines be built to accommodate internal inspection tools, such

as smart pigs, it has not yet established requirements for conducting

internal inspections. OPS believes that its proposed rule on the

enhanced protection of pipelines in high-consequence areas would

address these recommendations. However, this rule would address

pipelines only in areas with the highest risk of harming people or the

environment. According to officials from the Safety Board, this rule

would represent progress in improving the safety of pipelines in areas

where the consequences of accidents are greatest, but it would not fully

address the Safety Board’s 1987 recommendation that OPS require

periodic inspections of all natural gas and hazardous liquid pipelines for

corrosion or other damage.

• Since 1987, the Safety Board has issued two recommendations urging

OPS to ensure that operators are adequately trained to construct and

operate pipelines and to respond to emergencies. In 1994, OPS issued a

proposed rule that specified training requirements for operators. The

pipeline industry and OPS’ advisory committees responded that the

training requirements in this proposed rule were too specific. Because
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of the negative response to the proposed rule, OPS began a negotiated

rulemaking and issued a final rule in August 1999 that allows various

methods of demonstrating that an operator is qualified. For example,

the rule states that, until October 28, 2002, pipeline companies can rely

solely on an operator’s past performance to certify that the operator is

qualified. However, the Safety Board was dissatisfied, noting that if an

operator has not needed to respond to an emergency in the past, the

operator’s past performance might not be an accurate measure of

emergency preparedness. According to OPS officials, the agency is more

concerned with ensuring that pipeline operators are qualified than with

the specific methods pipeline companies use to qualify their personnel.

In other areas, OPS has recently taken actions that are responsive to the

Safety Board’s recommendations on excavation damage, corrosion control,

and data quality.

• Excavation damage—the leading cause of pipeline ruptures—has been

the topic of 13 recommendations issued by the Safety Board since 1989.

OPS has two primary initiatives to address this issue. As required by the

Transportation Equity Act for the 21st Century, enacted in 1998, OPS

issued a report in August 1999 that identified existing best practices to

prevent damage to underground facilities. Furthermore, OPS unveiled a

national public education campaign in June 1999, called “Dig Safely,”

that helps communities teach their citizens how to prevent damage to

pipelines and underground utilities.

• To control corrosion, the Safety Board recommended in 1987 that OPS

require operators of natural gas transmission and hazardous liquid

pipelines to periodically conduct inspections capable of identifying

corrosion-caused damage to pipelines. At that time, OPS required

natural gas and hazardous liquid pipeline operators to inspect for

corrosion on buried metallic pipe that had been exposed by excavation

and, if corrosion was found on a hazardous liquid pipeline, the operator

was required to dig up additional pipeline to determine the full extent of

the corrosion. In October 1999, OPS issued a final rule that requires

natural gas operators to follow the same procedures as hazardous liquid

pipeline operators. OPS also plans to update corrosion-control practices

for both gas and liquid pipeline regulations to incorporate the latest

safety practices for protecting steel pipe from corrosion.
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• OPS has several initiatives under way to improve the quality of the

accident data reported by pipeline operators. OPS is conducting a pilot

project with the American Petroleum Institute to encourage oil pipeline

operators to voluntarily report more detailed information than OPS

normally collects on accidents. For example, the pilot uses 20, rather

than 5, categories of accident causes and lowers the threshold of

accidents to be reported from 50 barrels of product spilled to 5 gallons

spilled. Data from this pilot, which should begin to be available in the

spring of 2000, may be better for analyzing trends in areas such as

causes, property damage, and remediation costs. OPS has also drafted a

new accident-reporting form for liquid pipeline accidents that

incorporates the expanded categories of accident causes that are being

used in the pilot, and it plans to modify the forms for natural gas

transmission and natural gas distribution pipeline accidents. Finally, in a

recent report, the Department of Transportation’s Inspector General

recommended that OPS collect more complete, detailed information on

the causes of accidents, and OPS agreed to do so.19

OPS and Safety Board officials have been meeting biannually to discuss

outstanding recommendations and work to resolve disagreements between

the agencies. Safety Board officials have been pleased with many of OPS’

actions and the improved communications between the agencies during the

last year. However, many of the actions are incomplete, and some, such as

OPS’ proposed rule requiring the enhanced protection of high-consequence

areas, will not fully address the recurring pipeline safety issues that have

prompted the Safety Board’s recommendations. Therefore, Safety Board

officials are waiting to see the results of OPS’ promised actions before

assessing the extent to which OPS’ responsiveness has improved.

OPS Has Not Fully

Implemented Statutory

Requirements

In addition to the Safety Board’s recommendations, 49 congressional

requirements have been imposed since 1988 to improve the safety of

pipelines and enhance OPS’ ability to oversee the pipeline industry.20

(App. IV lists these pipeline safety statutory requirements and their status.)

Twenty-two of these requirements have not been implemented, and 12 of

19Pipeline Safety Program, Office of Inspector General, U.S. Department of Transportation,

RT-2000-069 (Mar. 13, 2000).

20The Senate and House Appropriations Committees have also directed OPS to carry out

various activities in reports accompanying OPS’ annual appropriations. Several of these

directives reiterate the statutory requirements.
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them date from 1988 to 1992. (See table 4.) Ten of these 12 requirements

were to be completed by deadlines stated in the statutes and are now

between about 5 and 11 years past these deadlines.

Table 4: Status of Implementation of Statutory Requirements, 1988-2000

Source: GAO’s analysis of pipeline safety legislation from 1988-2000.

The statutory requirements often addressed the same issues as the Safety

Board’s recommendations. For example, three requirements from 1988,

1992, and 1996 called for periodic inspections of pipelines, five

requirements from 1988, 1992, and 1996 addressed the use of safety valves,

and four requirements from 1988, 1992, 1996, and 1998 addressed

excavation damage. These requirements also cover other issues. For

example, in October 1992, the Congress required OPS to define by October

1994 areas unusually sensitive to environmental damage from a hazardous

liquid pipeline rupture. According to OPS officials, the agency did not meet

the statutory deadline because reaching a consensus with other federal

agencies and environmental groups on a definition of these areas has been

complicated by the broad range of definitions currently in use. OPS issued

a proposed rule on a definition of areas unusually sensitive to

environmental damage on December 30, 1999, and expects to complete the

final rule by the end of 2000.

Both OPS and the Safety Board agree that there is a need to increase

pipeline safety in the areas where the Safety Board has made

recommendations—areas that are also frequently addressed by statutory

requirements. The agencies’ disagreement over several of the Safety

Board’s recommendations focus on how best to achieve that result.

Although some disagreements remain, the Safety Board has been

Legislation

Total

number of

requirements

Number of

requirements

not complete

Pipeline Safety Reauthorization Act of 1988 11 3

Oil Pollution Act of 1990 1 0

Offshore Pipeline Navigational Hazards (1990) 6 1

Pipeline Safety Act of 1992 15 8

Accountable Pipeline Safety and Partnership Act of 1996 15 10

Transportation Equity Act for the 21st Century (1998) 1 0

Total 49 22
B-283653

Page 35 GAO/RCED-00-128 Oversight of Pipeline Safety

encouraged by OPS’ recent actions to implement its recommendations and

the statutory requirements. We believe that it is essential for OPS and the

Safety Board to continue to work together to resolve their differences.

Conclusions We are concerned that OPS is discontinuing the use of states to help

conduct inspections of interstate pipelines primarily because of logistical

difficulties in scheduling systemwide inspections when states are involved.

States’ familiarity with pipelines in their jurisdictions could aid in

identifying the very risks that OPS is hoping to mitigate through its planned

risk management approach to safety regulation. This familiarity could

argue for states’ participation in reviewing integrity management programs

that pipeline companies would be expected to develop under a risk

management approach. In addition, a combined federal and state approach

to overseeing pipeline safety could better leverage federal resources.

OPS’ approach of working constructively with pipeline companies and

reducing its reliance on monetary penalties to enforce its regulations is

consistent with the actions of several other federal regulators, such as the

Federal Railroad Administration, as well as several state pipeline

regulators. However, a reduction in enforcement actions that result in fines

from nearly 50 percent to 4 percent represents a significant change in how

OPS obtains compliance with pipeline safety regulations. If pipeline

companies are achieving compliance through less punitive actions, then

OPS’ reduced reliance on fines may be reasonable. However, OPS has not

assessed whether (1) less punitive actions are effective in achieving the

desired results or (2) its actions to reduce reliance on fines go farther than

other agencies’ actions. An assessment of the degree to which OPS’ change

in approach to enforcement actions has maintained, improved, or lessened

compliance with safety regulations could provide a basis to judge whether

the agency is moving in the right direction.

Recommendations We recommend that the Secretary of Transportation direct OPS to work

with state pipeline safety officials to determine which federal pipeline

safety activities would benefit from state participation and, for those states

willing to participate, integrate state participation into these activities.

We further recommend that, if OPS issues a final rule requiring individual

pipeline companies to develop integrity management programs, the

Secretary should direct OPS to allow state inspectors to help review the
B-283653

Page 36 GAO/RCED-00-128 Oversight of Pipeline Safety

programs developed by the companies that operate in their states to ensure

that these companies have identified and adequately addressed safety risks

to their systems.

Finally, we recommend that the Secretary of Transportation determine

whether OPS’ reduced use of fines has maintained, improved, or decreased

compliance with pipeline safety regulations.

Agency Comments and

Our Evaluation

We provided a draft of this report to DOT for its review and comment. We

met with officials from DOT, including OPS’ Director, Office of Policy,

Regulations, and Training, to obtain their comments. The DOT officials

generally agreed with the draft report’s recommendations. The officials

stated that ongoing regulatory and legislative activities demonstrate that

efforts are under way to implement the draft report’s recommendation that

OPS work closely with the states and their pipeline inspectors to further

improve the level of pipeline safety. For example, DOT’s proposed

legislation to reauthorize the pipeline safety program would include

specific authority for states to participate in new construction inspections

and accident investigations on interstate pipelines. The officials told us that

DOT’s initiatives are intended to enable state inspectors to better focus

their oversight efforts and to improve OPS’ interactions with the states. The

officials also told us that DOT is moving to substantially increase the

funding available for state inspection activities and, for the first time,

provide funding for certain state inspection activities on interstate

pipelines. We are pleased that DOT recognizes the importance of working

cooperatively with the states in overseeing pipeline safety. However, we

continue to believe that, in addition to new pipeline construction and

accident investigations, DOT should specifically allow the states to

participate in reviews of interstate pipeline companies’ integrity

management programs, as we recommended in the draft report.

According to the officials, while OPS increasingly favors the use of

corrective action and other compliance orders, it maintains all traditional

enforcement tools and applies them when necessary. Furthermore, the

officials told us that DOT’s proposal to reauthorize the pipeline safety

program is intended to strengthen the enforcement tools available to OPS.

The officials maintain that the new enforcement approach has obtained

more immediate and thorough corrective and remedial actions than would

have been obtained through an approach based solely on increased fines.

We recognize that DOT’s pipeline safety program reauthorization proposal

is intended to strengthen the enforcement tools available to OPS. However,
B-283653

Page 37 GAO/RCED-00-128 Oversight of Pipeline Safety

while DOT officials claim that OPS’ new approach of using corrective

action and other compliance orders in lieu of fines has achieved benefits

that would not have been obtained otherwise, a formal assessment of this

new approach, as we recommended in the draft report, is needed to

determine whether it is providing an equal, greater, or lesser level of

compliance with the regulations.

Finally, the officials emphasized that DOT will continue to require full

regulatory compliance even as it moves to further refine its focus on risk.

Under OPS’ integrity management program for the enhanced protection of

pipelines in high-consequence areas, DOT plans to supplement regulatory

compliance with a comprehensive examination of individual pipeline

systems to identify and act on potential risk factors. DOT told us that this

approach will make use of expertise from all aspects of pipeline design,

construction, and operation to integrate information in a supplemental

evaluation of systemwide risk factors. Once the risks are identified,

operators will be required to act on the assessment through repair,

prevention, and mitigation. We modified our draft report to further clarify

that OPS’ proposed integrity management program for the enhanced

protection of pipelines in high-consequence areas is intended to be a

supplement to, rather than a replacement of, the existing pipeline safety

regulations.

DOT officials also provided technical clarifications, which were

incorporated as appropriate.

Scope and

Methodology

To determine the extent of pipeline accidents from 1989 through 1998 (the

most recent year for which data were available), we collected and analyzed

OPS’ data on pipeline accidents. We did not independently verify the

reliability of the data. To ensure an objective comparison across all types of

pipelines, we included in our analysis only those accidents that met the

reporting criteria common to all types of pipelines—accidents that resulted

in a fatality, an injury requiring hospitalization, or $50,000 or more in

property damage. We defined these accidents as “major accidents.” We also

reviewed more extensive data on the causes of accidents compiled by the

Association of Oil Pipe Lines, the American Petroleum Institute, and the

American Gas Association.

To determine OPS’ implementation of the risk management demonstration

program, we reviewed the statutory requirements for the program and

program documents maintained on OPS’ web-based document
B-283653

Page 38 GAO/RCED-00-128 Oversight of Pipeline Safety

management system, including program guidance and project applications.

We also interviewed OPS officials and representatives from the pipeline

companies participating in the program.

To describe OPS’ inspection and enforcement efforts since the 1996 act, we

reviewed data on OPS’ inspections and enforcement actions from 1990

through 1998 and analyzed trends in these activities. We interviewed OPS

officials and representatives from the pipeline industry and environmental

groups. We conducted telephone interviews with state pipeline safety

officials in 12 states that have acted as interstate agents within the last

5 years—Arizona, California, Connecticut, Iowa, Michigan, Minnesota,

Nevada, Ohio, New York, Rhode Island, Utah, and West Virginia. We also

visited three states—Texas, Virginia, and Washington—where major

pipeline accidents were investigated by the Safety Board and officials have

sought a greater role for states in pipeline safety.

To determine OPS’ responsiveness to the National Transportation Safety

Board’s recommendations and statutory requirements, we reviewed the

Safety Board’s reports and recommendations since 1989, analyzed statistics

on the recommendations since 1967, and discussed the results of our

analysis with Safety Board and OPS officials. We did not assess the merits

of the Safety Board’s recommendations or the adequacy of OPS’ response.

We reviewed pipeline safety statutes, annual appropriations acts, related

congressional committee reports, and reports by OPS to identify statutory

requirements since 1988. We reviewed OPS’ reports and analyses of the

status of the requirements. We did not assess the adequacy of OPS’

response to statutory requirements or independently verify the status of the

requirements.

To determine the status of the ongoing investigation of the accident in

Bellingham, Washington, we interviewed representatives and reviewed

documents from the following agencies and groups: the National

Transportation Safety Board, OPS’ Western Region, the Washington

Utilities and Transportation Commission, the Washington State Governor’s

Fuel Accident Prevention and Response Team, the city of Bellingham,

SAFE Bellingham, and Olympic Pipe Line Company.

We conducted our work from August 1999 through April 2000 in

accordance with generally accepted government auditing standards.
B-283653

Page 39 GAO/RCED-00-128 Oversight of Pipeline Safety

As arranged with your office, unless you publicly announce its contents

earlier, we plan no further distribution of this report until 30 days after the

date of this letter. At that time, we will send copies of the report to

congressional committees and subcommittees responsible for

transportation safety issues; the Honorable Rodney E. Slater, Secretary of

Transportation; the Honorable Kelley S. Coyner, Administrator, Research

and Special Programs Administration; the Honorable Jim Hall, Chairman,

National Transportation Safety Board; the Honorable Jacob Lew, Director,

Office of Management and Budget; and other interested parties. We will

make copies available to others upon request.

If you or your staff have any questions about this report, please contact me

at (202) 512-3650. Key contributors to this report are listed in appendix V.

Sincerely yours,

Phyllis F. Scheinberg

Associate Director, Transportation Issues
Page 40 GAO/RCED-00-128 Oversight of Pipeline Safety

Appendix I

The Bellingham, Washington, Pipeline Apendxies

Accident ApendxiI

The Olympic Pipe Line Company operates a pipeline system consisting of

about 400 miles of pipelines that transport petroleum products from

refineries at Cherry Point, Ferndale, and Anacortes in northwestern

Washington to Portland, Oregon, and intermediate delivery points.

Products transported include gasoline, distillates (heating oil and diesel

fuel), and jet fuel. The system is operated by remote control from an

operations center located in Renton, Washington.

On June 10, 1999, one of Olympic’s pipelines transporting gasoline ruptured

in the Whatcom Falls Park area of Bellingham, Washington. About

250,000 gallons of gasoline from the pipeline entered the Hannah Creek and

Whatcom Creek where the fuel was ignited, resulting in three fatalities and

eight injuries. In addition, the banks of the creek were destroyed over a

1.5-mile section, and several buildings adjacent to the creek were severely

damaged.

Pipeline Rupture on

June 10, 1999

Although the investigation of the accident is ongoing, the National

Transportation Safety Board (the Safety Board) and the Department of

Transportation’s Office of Pipeline Safety (OPS) have preliminarily

reconstructed the events leading up to the pipeline rupture. Shortly before

the rupture occurred, pipeline operators attempted to start a pump at the

Woodinville pumping station to facilitate the smooth flow of gasoline

through the pipeline. (See fig. 7.) The pump did not engage, and pressure

started to build within the pipeline. A relief valve at the Bayview station

was designed to divert the gasoline from the pipeline to a tank to relieve the

increasing pressure, and a block valve, also located at the Bayview station,

was designed to close and stop the flow of gasoline. The Safety Board

believes that the block valve closed as it should have done. However,

gasoline continued to be pumped into the pipeline at Cherry Point, causing

the pressure in the pipeline segment between Cherry Point and Bayview to

continue increasing. The pipeline subsequently ruptured about midway

along the segment at the Bellingham water treatment plant, near Whatcom

Creek.
Appendix I

The Bellingham, Washington, Pipeline

Accident

Page 41 GAO/RCED-00-128 Oversight of Pipeline Safety

Figure 7: Location of Olympic Pipe Line Rupture

Source: National Transportation Safety Board.

Oregon

Olympia

Portland

Seattle

Sea Tac Renton

Woodinville

Allen 

16”

CANADA 

UNITED STATES

Anacortes

Bellingham

(Rupture Location) 

16”

20”

14”

Washington

 Bayview

Ferndale

Cherry Point
Appendix I

The Bellingham, Washington, Pipeline

Accident

Page 42 GAO/RCED-00-128 Oversight of Pipeline Safety

According to the Chairman of the Safety Board, preliminary data show that

when the rupture occurred, the pressure in the pipeline was well above

normal operating levels. However, the pressure was substantially below the

maximum pressure that a pipe of this design and size should have been able

to withstand, and it was below the maximum allowable surge pressure

permitted by regulatory standards.

According to Safety Board officials, the pipeline shut down after the

rupture. However, Olympic Pipe Line controllers restarted the pipeline

about 45 minutes later, and gasoline was pumped into the damaged

segment for about 17 minutes. Between 250,000 and 300,000 gallons of

gasoline (from the initial rupture and the subsequent restart of the pipeline)

flowed from the damaged pipeline to the Hannah Creek and Whatcom

Creek. Whatcom Creek—a salmon habitat—flows through Whatcom Falls

Park in Bellingham.

The Safety Board’s

Investigation of the

Accident

Investigators from the Safety Board are examining several factors that may

have caused or contributed to the accident, including excavation damage,

valve malfunctioning, operator training, and computer issues. However,

several key activities in the Safety Board’s investigation have been

suspended because (1) Olympic Pipe Line Company employees with direct

knowledge of the events have exercised their Fifth Amendment rights and

have not responded to the Safety Board’s questioning and (2) the

Department of Justice halted destructive testing of the pipeline segment in

order to preserve evidence. On April 5, 2000, the Safety Board was

authorized to proceed with the testing of the pipeline segment.

The Safety Board’s preliminary visual inspection of the ruptured pipeline

segment indicated external damage to the pipeline at the point of rupture

and additional damage to the area. In 1993 and 1994, a contractor working

on behalf of the city of Bellingham installed new water lines across

Olympic’s pipeline at points approximately 20 feet and 10 feet south of the

rupture. In 1991, an internal inspection of the pipeline did not identify any

anomalies in the immediate vicinity of the rupture. However, two internal

inspections conducted in 1996 and 1997 after the construction of the water

lines identified several anomalies in the vicinity of the rupture. According

to the Chairman of the Safety Board, Olympic Pipe Line indicated that the

anomalies did not meet the applicable criteria for excavating the pipeline

for a closer examination. The Safety Board is determining what criteria

were used and plans to meticulously test the ruptured pipeline segment to

determine whether external damage may have contributed to the rupture.
Appendix I

The Bellingham, Washington, Pipeline

Accident

Page 43 GAO/RCED-00-128 Oversight of Pipeline Safety

The Safety Board is also investigating the performance of the relief valve

and the block valve at the Bayview station. Because Olympic modified the

relief valve when it was installed, the Safety Board is examining whether

the company followed the manufacturer’s specifications for the

modification. In addition, preliminary information indicates that the block

valve had closed over 50 times in the 6 months prior to the accident, often

because of pressure buildups similar to the one that occurred before the

accident on June 10. The Safety Board is evaluating these events to

determine the pressures involved, the functioning of the relief valve, and

the possible impact of the pressure buildups on the overall integrity of the

pipeline segment that ruptured.

The Chairman of the Safety Board also stated that the Safety Board wants

to document and analyze the data available to controllers at the time of the

accident. According to the Chairman, the controllers seem to have been

unaware of the rupture for an extended period of time and the fact that

they restarted the pipeline after the rupture suggests a significant

performance failure. The Chairman noted that the Safety Board does not

know whether this can be traced to insufficient training, inadequate

qualifications, equipment malfunctions, poor design in the computer-based

control system, or some other undetermined factor.

Finally, Olympic initially reported that the computer system that controls

the pipeline experienced a “slowdown” during the accident that affected

the ability of the controllers to observe the pipeline’s functions and to

change settings. The Safety Board’s preliminary analysis of the computer

tapes did not identify a slowdown. Olympic has reported that such a

slowdown cannot be verified or reproduced.

OPS’ Actions

Following the Accident

On June 18, 1999, OPS issued a corrective action order to Olympic Pipe

Line Company (owned and operated by Equilon Pipeline Company, LLC)

which directed Olympic not to operate the damaged pipeline segment until

the company, among other things, reviewed its computer system to

determine the cause of the slowdown and take corrective action, tested

mainline valves, and submitted a plan to OPS addressing factors that

contributed to the rupture. The order also restricted the operating pressure

on the remainder of the pipeline until OPS approves a return to normal

operating pressure. The order was amended on August 10, 1999, and again

on September 24, 1999, to address safety issues identified during the

ongoing investigation. For example, the subsequent orders required

Olympic to further reduce the pressure on certain pipeline segments,
Appendix I

The Bellingham, Washington, Pipeline

Accident

Page 44 GAO/RCED-00-128 Oversight of Pipeline Safety

develop and implement a training program for controllers on the use of the

computer system (including abnormal operations), and conduct

hydrostatic tests of certain segments of the pipeline (draining the pipeline,

filling it with water, and increasing the pressure within the pipeline to

identify weak points). In addition to the corrective action order, OPS issued

an advisory to all pipeline operators to check the adequacy of the computer

resources devoted to monitoring and controlling their pipeline operations.

OPS inspectors have been monitoring Olympic’s corrective actions. The

inspectors are (1) working as a party to the Safety Board’s investigation,

(2) conducting an enforcement investigation, and (3) monitoring upgrades

and repairs to the pipeline in accordance with the corrective action order.

OPS also retained an independent expert to evaluate complex data from

the internal inspections conducted in 1996 and 1997. In addition, OPS

stationed a pipeline inspector in Washington State. This inspector will

oversee the safety and environmental integrity of pipelines in the upper

Northwest region and work on issues related to the Bellingham accident.

On January 18, 2000, Olympic asked OPS for permission to restart the

pipeline. As of April 2000, OPS officials had sent a response to Olympic

detailing areas where it needed to take additional actions before the

pipeline could be returned to limited service. When OPS decides to allow

Olympic to restart the pipeline, the pipeline will be brought back into

service in incremental steps.

Actions Taken by the

City of Bellingham and

Its Citizens

Within a week after the accident, officials from the city of Bellingham

realized that the agreement under which Olympic operated its pipeline

within the city limits had expired. According to city officials, the need for

Olympic to re-obtain the city’s permission to operate its pipeline gave them

some added leverage in negotiating several agreements with Olympic. The

city extended the expired agreement until May 4, 2000, provided that

Olympic complied with two other agreements between the city and

Olympic—a safety action plan and a master agreement.

The safety action plan includes safety-related activities to be performed by

Olympic before the section of the pipeline that ruptured can be restarted at

reduced pressure, as well as activities to be performed at various stages

after restarting the pipeline. These activities include (1) the testing of

existing valves and installation of new valves; (2) hydrostatic testing of the

pipeline; (3) computer testing and modifications; (4) the installation of an

additional leak detection system; (5) an internal inspection of the pipe
Appendix I

The Bellingham, Washington, Pipeline

Accident

Page 45 GAO/RCED-00-128 Oversight of Pipeline Safety

within 3 months of startup (and in any event no later than 6 months after

startup); (6) field inspections and repairs based on the results of the

internal inspection, and (7) a management audit to be performed by an

independent party. OPS incorporated participation in the management

audit into the September 24, 1999, amendment to its corrective action

order.

On February 11, 2000, Olympic sent a letter to the city of Bellingham

responding to the conditions for restarting the pipeline. The city continues

to have concerns about Olympic’s response.

The master agreement specifies that Olympic cannot restart the pipeline

until it has satisfied the requirements in the city’s safety action plan and

OPS’ corrective action order. In addition, the master agreement requires

Olympic to study the feasibility of rerouting the pipeline around

Bellingham. On February 1, 2000, Olympic submitted a report to the city in

which it concluded that rerouting the pipeline was not feasible because it

was unlikely that a new route would gain permitting approval from state

and federal agencies. As of April 2000, the city had not responded to the

report’s conclusions.

One week after the accident, a group of citizens from Bellingham formed a

group—SAFE Bellingham—to ensure that the creek would be restored,

that Olympic would be held accountable, and that actions would be taken

to mitigate future accidents. SAFE Bellingham has organized a coalition of

communities that have experienced pipeline accidents to promote changes

to federal pipeline safety regulations and has drafted a proposal for a local

advisory committee to monitor pipeline safety within states.

Actions Taken by the

State of Washington

The governor of Washington established a task team after the accident to

evaluate pipeline safety within the state. The task team issued a report in

December 1999 that recommends changes in law and practice at the

federal, state, and local levels and changes in practice by fuel transmission

pipeline operators in Washington. For example, the report recommends

that the state pursue (1) federal regulation that would allow states to

regulate the portions of interstate pipelines within their borders using

standards more stringent than OPS’, (2) federal legislation that would

authorize states to receive higher levels of grant support from OPS, and

(3) state executive branch and legislative changes that would strengthen

pipeline safety.
Appendix I

The Bellingham, Washington, Pipeline

Accident

Page 46 GAO/RCED-00-128 Oversight of Pipeline Safety

As of April 2000, the state was working on an agreement with OPS

regarding the inspection of interstate pipelines. On March 28, 2000, the

governor signed a bill that establishes a statewide program to improve

pipeline safety in Washington by having, among other things, the state’s

Utilities and Transportation Commission adopt new regulations and

provide technical assistance to local governments. The bill also establishes

a citizen advisory committee to help the public, local governments, and the

industry work with the state on pipeline safety. Finally, the bill increases

the penalties for failing to call a central number to identify the location of

pipelines before digging.

Actions Taken by

Olympic Pipe Line

Company

In addition to responding to OPS’ corrective action order and the city of

Bellingham’s safety action plan, Olympic issued a corridor safety action

plan in October 1999 that applied many of the same actions being taken in

the Bellingham area to the entire pipeline corridor from Ferndale to

Portland. For example, Olympic’s action plan includes requirements for

valve testing and internal inspections along the entire pipeline.

Representatives from Olympic are on a committee with representatives

from the city of Bellingham and other consultants to restore and improve

Hannah and Whatcom creeks. Olympic has provided the initial funding for

restoration and improvement efforts, which include erosion control,

replanting, and building new salmon spawning pools. According to a

member of the committee, Whatcom Creek’s water quality has been

restored and several species of salmon have been observed in the creek.

Barge and truck transport are being used to deliver petroleum products

during the shutdown of the damaged pipeline segment. According to

attorneys representing Olympic, maintaining delivery has been difficult at

times, especially since Olympic is the sole supplier of jet fuel to the SeattleTacoma Airport.
Page 47 GAO/RCED-00-128 Oversight of Pipeline Safety

Appendix II

Maps of Natural Gas Transmission and

Hazardous Liquid Pipelines ApendxiI

Figure 8: Locations of Natural Gas Transmission Pipelines

Source: OPS, based on data from MAPSearch Services.

N

W E

S

Atlantic

Ocean

Gulf of

Mexico

Pacific

Ocean

GA

AL

TN

KY

IN

MO

IL

MI

WI

IA

MN

ND

SD

NE

NM

KS

TX

CO

AZ

UT

NV

WY

MT

ID

CA

OR

WA

Canada

Mexico

VT

ME

NH

NY

FL

NC

SC

VA

MS

OH

DE

NJ

MD

PA

WV

LA

OK

AR

CT RI

MA
Appendix II

Maps of Natural Gas Transmission and

Hazardous Liquid Pipelines

Page 48 GAO/RCED-00-128 Oversight of Pipeline Safety

Figure 9: Locations of Hazardous Liquid Pipelines

Source: OPS, based on data from MAPSearch Services.

N

W E

S

Pacific

Ocean

Gulf of

Mexico

Atlantic

Ocean

Mexico

Canada

ID

OR

WA

NV

CA

UT

AZ

CO KS

SD

MT

WY

NM

TX

LA

NE

ND

MN

IA

WI

MI

IL

MO

IN

KY

OH

TN

AL

AR

MS

WV

VA

SC

GA

FL

NC

PA

MD

NH

VT

NY

ME

RI

MA

CT

NJ

DE

OK
Page 49 GAO/RCED-00-128 Oversight of Pipeline Safety

Appendix III

Status of Risk Management Demonstration

Projects ApendxiI

Since the inception of the risk management demonstration program, OPS

has approved six pipeline companies’ risk management projects for the

program. These individual projects are designed to demonstrate the

benefits of risk management under a variety of conditions, including

differences in products, the ages of pipeline systems, environments,

geography, and operating conditions (see table 5).

Table 5: Projects Approved for the Risk Management Demonstration Program

Source: GAO’s analysis of information from OPS.

The direct federal costs of the risk management demonstration program

are expected to be nearly $8 million from fiscal year 1996 through fiscal

year 2000. According to OPS officials, OPS has not funded the participant

companies’ costs for the risk management demonstration projects but has

Operator Regions affected Project focus Date approved

Equilon Pipeline Southwest Equilon is including two separate interstate pipeline systems in its project: a

205-mile segment of an ethylene pipeline and a 260-mile segment of a

carbon dioxide pipeline. For these pipeline segments, Equilon is developing

a comprehensive risk management program for assessing all hazards and

risks associated with the operation of these pipelines. A major focus of the

project is damage prevention during excavation and construction.

March 1998

Exxon Mobil Central Exxon Mobil is demonstrating its release prevention (tank integrity) program

at its crude oil breakout facility in Patoka, Illinois. The project will examine

how Exxon Mobil’s release prevention measures will work in conjunction

with OPS’ proposed standards for aboveground storage tanks.

August 1998

Phillips Pipe Line

Company

Southwest Phillips is using risk management along a 60-mile segment of both an

18-inch and a 12-inch refined oil products pipeline. The project will explore

ways of minimizing the risks associated with excavation work along the

pipelines to reduce or eliminate damage from outside forces.

August 1998

Kinder Morgan, Inc. Central, Southwest The company is incorporating risk management into a 13,000-mile natural

gas pipeline system. It hopes to form a comprehensive risk management

program based on existing company programs such as pipeline integrity,

regulatory compliance management, and emergency response.

December 1998

Chevron Pipe Line Western Chevron is including a 330-mile portion of its Salt Lake Products Pipeline

System in the program. The system consists of two 8-inch product

pipelines, one transporting gasoline and the other distillates such as diesel

and jet fuel. Among other tasks, Chevron will conduct internal pipeline

inspections and geologic hazard assessments of the pipelines for its

project.

February 1999

Northwest Pipeline Western Northwest is developing a risk management program for its entire

3,900-mile natural gas system. The project will explore means of assessing

and addressing risks presented by a pipeline in rugged terrain susceptible

to land movement and investigate the risk-reduction benefits of certain new

technologies.

January 2000
Appendix III

Status of Risk Management Demonstration

Projects

Page 50 GAO/RCED-00-128 Oversight of Pipeline Safety

incurred direct support costs for personnel, travel, and contractor support

for evaluating and auditing the demonstration projects. In addition, OPS

has provided grants to states totaling about $340,000 for travel costs

associated with the projects. These direct support costs decreased from a

total of about $1.8 million in fiscal year 1996 (the first year of the program)

to about $1.4 million in fiscal year 1999, but they are expected to increase

to about $1.6 million in fiscal year 2000, primarily because of increases in

contractor support costs. (See table 6.)

Table 6: Federal Cost of the Risk Management Demonstration Program, by Fiscal Year

a

Estimated salary and benefits for five full-time equivalent employees per year.

b

According to OPS officials, this is an amount obligated for the 15-month period from Oct. 1, 1999,

through Dec. 31, 2000.

Source: GAO’s analysis of OPS’ documents.

Fiscal year

Description 1996 1997 1998 1999 2000 Total

Federal salary and benefitsa $355,000 $363,000 $379,000 $393,000 $425,000 $1,915,000

Estimated travel costs 200,000 200,000 200,000 200,000 200,000 1,000,000

Contractor support costs 1,249,956 1,069,053 811,599 708,346 900,000b 4,738,954

State grants 0 40,000 100,000 100,000 100,000 340,000

Total $1,804,956 $1,672,053 $1,490,599 $1,401,346 $1,625,000 $7,993,954
Page 51 GAO/RCED-00-128 Oversight of Pipeline Safety

Appendix IV

OPS’ Action on Statutory Requirements,

1988-2000 ApendxiIV

This appendix consists of tables that summarize (1) the requirements for

OPS established in six statutes and (2) the actions OPS has taken since

1988 in response to these requirements.

Table 7: Pipeline Safety Reauthorization Act of 1988 (P.L. 100-561, Oct. 31, 1988)

Section Statutory requirement Status

102 (gas)

202 (liquid)

Reporting standards: Within 1 year, establish

standards for operators to provide information,

including the following: Name, address, phone

number; Map; Pipeline characteristics; Description of

products transported; Operations manual; Emergency

response plan.

Closed: 49 C.F.R. 192 and 195 require gas and hazardous liquid

pipeline operators to (1) maintain records of the characteristics

and maintenance history of their pipelines and (2) prepare an

operations manual and an emergency manual. In addition, OPS,

in conjunction with the National Pipeline Mapping System, has

developed and published standards for collecting information on

pipelines and their environment. OPS and the states are now

receiving data from the pipeline companies.

In addition, OPS is working with the hazardous liquid pipeline

industry to develop a voluntary annual report that contains more

information than is currently required, by regulation, from natural

gas pipeline companies. This information will be provided to

OPS by the end of 2000 through a voluntary data initiative of the

American Petroleum Institute. The information anticipated from

this ongoing initiative will likely make it unnecessary to require

an annual report from hazardous liquid pipeline companies.

102 (gas)

202 (liquid)

Pipeline inventory: Establish standards to require

operators, within 1 year, to complete and maintain an

inventory of all types of pipe used, including the

materials used and a history of any leaks.

Open: OPS formed a data team with the hazardous liquid

pipeline industry to provide for the voluntary submission of data

on pipeline facilities. During 1999, the hazardous liquid pipeline

industry pilot-tested a system to assess the effects of the team’s

data collection recommendations; an analysis of the results will

soon be completed. Pipe inventory standards for voluntary

reporting are subject to further development. In 2000, OPS

revised its annual report forms for gas and hazardous liquid

transmission pipeline companies to provide better inventory

information.

105(2) (gas)

209 (liquid)

Accident coordination: Within 1 year, establish

procedures to more effectively coordinate the

response of federal agencies and the states to

pipeline accidents.

Closed: OPS coordinates accident response procedures with

the National Transportation Safety Board, the Environmental

Protection Agency, the Occupational Safety and Health

Administration, the Coast Guard, the Federal Railroad

Administration, and the Minerals Management Service through

memorandums of understanding, letters of agreement, and

informal undertakings. Parts 192 and 195 both require pipeline

companies to provide information to local emergency response

organizations to improve coordination during accidents. Liquid

pipeline companies coordinate with federal response agencies

and state and local agencies in planning for pipeline spills under

the Oil Pollution Act. OPS participates in emergency response

exercise programs.

Continued
Appendix IV

OPS’ Action on Statutory Requirements,

1988-2000

Page 52 GAO/RCED-00-128 Oversight of Pipeline Safety

Source: For columns 1 and 2, GAO’s analysis of pipeline safety statutes; for column 3, status reports

from OPS.

108(a)(2) (gas)

207(a) (liquid)

Inspection frequency: Inspect and, as appropriate,

require the testing of pipeline facilities at specified

intervals, but no less frequently than once every

2 years; master meter operators can be inspected

less frequently; the frequency and type of inspections

shall be determined on a case-by-case basis,

considering factors such as location, characteristics,

and materials transported.

Closed: The Accountable Pipeline Safety and Partnership Act of

1996 (49 U.S.C. 60108(b)) eliminated the requirement for

testing at 2-year intervals.

108(b) (gas)

207(b) (liquid)

Smart pig accommodation: Establish standards

requiring that new and replacement pipe shall

accommodate the passage of smart pigs.

Open for certain gas pipelines: A final rule for all pipelines was

published (59 F. R. 17275, 4/12/94). Notice 2 (59 F.R. 49896,

9/30/94) extended the compliance date for existing gas

transmission lines and modified the requirement for offshore

and rural gas transmission lines. Notice 3 (60 F.R. 7133, 2/7/95)

suspended enforcement of the final rule’s requirements for

modifications to sections of onshore gas transmission lines and

for new and existing offshore gas transmission lines. A final rule

in response to petitions for reconsideration is being prepared for

publication in 5/00.

108(c)(gas) Master meter study: Assess the need for an improved

inspection program for master meter systems and

issue a report within 18 months.

Open: A final report, An Analysis of Natural Gas Master Meter

Systems (Definition and Program) from a Federal Perspective,

was issued 6/15/79. An additional study on master meter

systems was drafted following a survey of the states. The data

on master meter systems included in the report are being

updated. The report will be finalized and issued by the end of

2000.

211(a) (liquid) Carbon dioxide: Regulate carbon dioxide transported

by pipeline and amend regulations as appropriate to

ensure the safe transportation of carbon dioxide by

pipeline.

Closed: 49 C.F.R. part 195 was amended for carbon dioxide on

6/21/91.

303(a) One-call systems: Within 18 months, issue regulations

establishing minimum federal requirements for

establishing and operating one-call notification

systems for adoption by states.

Closed: 49 C.F.R. 198, Subpart C, 9/20/90 addresses one-call

notification; also, 49 C.F.R. 192.614 and 49 C.F.R. 195.442,

11/19/97, mandate states’ participation in one-call systems.

304 Smart pig feasibility study: Assess the feasibility of

requiring the inspection of transmission facilities with

smart pigs at periodic intervals and issue a report

within 18 months.

Closed: OPS issued a report, Instrumented Internal Inspection

Devices, in 11/92.

305 Emergency flow valve feasibility study: Study the

safety, cost, feasibility, and effectiveness of requiring

operators to install emergency flow-restricting devices

and issue a report within 1 year.

Closed: A study sponsored by the Research and Special

Programs Administration, Emergency Flow Restricting Devices

Study, was issued in 3/91.

306 Feasibility of regulating excavation activity: Assess the

feasibility of regulating persons whose excavation

activities may result in damage to pipeline facilities

and issue a report within 1 year.

Closed: A report, Examination of the Feasibility of Regulating

Excavators, was issued in 10/90.

Section Statutory requirement Status

Continued from Previous Page
Appendix IV

OPS’ Action on Statutory Requirements,

1988-2000

Page 53 GAO/RCED-00-128 Oversight of Pipeline Safety

Table 8: Oil Pollution Act of 1990 (P.L. 101-380, Aug. 18, 1990)

Source: For columns 1 and 2, GAO’s analysis of pipeline safety statutes; for column 3, status reports

from OPS.

Table 9: Offshore Pipeline Navigational Hazards (P.L. 101-599, Nov. 16, 1990)

Section Statutory requirement Status

4202(a)(6),

(b)(4)

Response plans for onshore oil pipelines: Issue

regulations for oil spill response plans for onshore oil

pipelines by 8/18/92.

Closed: An interim final rule on onshore facilities was published

(58 F.R. 244, 1/5/93). Response plans have been submitted

under this interim rule. The final rule, incorporating experience

in operating spill response systems and reviewing plans, is to be

issued in 5/00.

Section Statutory requirement Status

1(a) (gas)

1(b) (liquid)

Reporting standards: Within 6 months of 11/16/90,

establish standards defining “exposed pipeline facility”

and “hazard to navigation.”

Closed: 49 C.F.R. 192.3 and 195.2 define these terms.

1(a) (gas)

1(b) (liquid)

Hazardous conditions: Establish, by regulation, a

program requiring operators of offshore and navigable

water pipelines to report potential or existing

navigational hazards involving pipeline facilities to the

Secretary through the Coast Guard (as enacted,

limited to the Gulf of Mexico and its inlets).

Closed: 49 C.F.R. 191.27, 192.612, 195.57, and 195.413 specify

reporting procedures for pipelines in the Gulf of Mexico and its

inlets. In addition, OPS issued alert notices to the offshore

fishing industry (ALN-90-01) warning of hazards to fishing

vessels from exposed pipelines and to Gulf of Mexico operators

(ALN-98-03) warning of the possibility of exposed pipelines after

Hurricane Georges.

1(a) (gas)

1(b) (liquid)

Permanent inspections: Establish an inspection

program for offshore and navigable water pipelines no

later than 30 months after 11/16/90 (as enacted,

limited to the Gulf of Mexico and its inlets).

Open: OPS signed a memorandum of understanding with the

Minerals Management Service to define inspection

responsibilities for offshore pipelines. A proposed rule for

periodic underwater pipeline inspections is now being prepared

for publication by mid-2000.

1(a) (gas)

1(b) (liquid)

Burial: Require, by regulation, that exposed or

hazardous pipelines be buried within 6 months after

the date that the condition of the pipeline is reported

to the Secretary (unless the Secretary extends the

time period for compliance).

Closed: 49 C.F.R. 192.612 and 195.413 impose requirements

for pipelines in the Gulf of Mexico and its inlets.

Continued
Appendix IV

OPS’ Action on Statutory Requirements,

1988-2000

Page 54 GAO/RCED-00-128 Oversight of Pipeline Safety

Source: For columns 1 and 2, GAO’s analysis of pipeline safety statutes; for column 3, status reports

from OPS.

2 Navigational hazards: Establish a program to

encourage fishermen and other vessel operators to

report potential or existing navigational hazards

involving pipelines to the Secretary through Coast

Guard field offices.

Closed: 49 C.F.R. 191.23, 191.25, 192.27, 192.612, 192.615,

195.52-.58 establish procedures for reporting accidents and

safety-related conditions for both gas and hazardous liquid

pipelines. OPS issued a report, Safety-related Condition

Reporting, in 7/88. In addition, OPS issued alert notices to the

offshore fishing industry (ALN-90-01) warning of hazards to

fishing vessels from exposed pipelines and to Gulf of Mexico

operators (ALN-98-03) warning of the possibility of exposed

pipelines after Hurricane Georges. Fishermen in the Gulf of

Mexico now voluntarily provide reports on fishing net snags

(which may or may not be on a pipeline), known as “hang”

reports. These reports may result in compensation if the

Minerals Management Service determines that a hang is on a

pipeline facility. Louisiana also maintains its own Fisherman

Gear Fund to compensate fishermen for lost nets and

equipment in case of hangs on pipelines or production facilities.

3 Study: Study several issues related to underwater

pipelines and report to the Congress on the results of

actions no later than 6 months after 11/16/90.

Closed: OPS (1) informed operators and fishermen of the

problems posed by exposed underwater pipelines and required

the reporting of safety-related conditions, (2) completed its

collection of computer-assisted maps of all offshore oil and gas

lease blocks, (3) contracted with Texas A&M University for a

study, issued in 1/98. The study recommended that OPS (1)

establish regulations requiring the inspection of pipelines to

determine their depth of burial and any need for reburial, (2) use

risk analysis to determine the periodicity of future surveys, and

(3) require operators to maintain pipelines 3 feet below the

natural bottom and develop a mandatory one-call system for

marine pipelines. OPS is drafting a proposed rule that will

incorporate these recommendations.

Section Statutory requirement Status

Continued from Previous Page
Appendix IV

OPS’ Action on Statutory Requirements,

1988-2000

Page 55 GAO/RCED-00-128 Oversight of Pipeline Safety

Table 10: Pipeline Safety Act of 1992 (P.L. 102-508, Oct. 24, 1992)

Section Statutory requirement Status

102(a)(2) (gas)

202(a)(2)

(liquid)

High-density population areas (for gas and liquid) and

environmentally sensitive areas (for liquid): Within 2

years, issue regulations establishing criteria for the

identification of all pipeline facilities that are located in

high-density and environmentally sensitive areas.

Open: On 4/24/00, OPS issued a proposed rule requiring

additional testing, inspection, and remediation of hazardous

liquid pipelines in high-consequence areas. The agency issued,

on 12/30/99, a proposed rule defining U.S. areas unusually

sensitive to environmental damage (64 F.R. 73464). (Comments

are due on 6/27/00). An additional proposed rule for the

inspection and testing of gas transmission pipelines in highconsequence areas will be issued in 2000.

103(5) (gas)

203(5) (liquid)

Update inspections/smart pigs: Within 3 years, issue

regulations requiring the periodic inspection of

pipelines in high-density and environmentally

sensitive areas, specifying the circumstances, if any,

under which inspections should be conducted using

smart pigs; when smart pigs are not required, require

an inspection method that is at least as effective in

providing for the safety of the pipeline.

Open: A proposed rule to require periodic inspections of

hazardous liquid pipelines in high-consequence areas was

issued on 4/24/00.

104 (gas) Excess flow valves: (1) Within 18 months, issue

regulations prescribing the circumstances, if any,

under which operators must install excess flow valves;

(2) within 2 years, issue regulations requiring

operators to notify, in writing, customers whose lines

do not require but can accommodate excess flow

valves that such valves shall be installed at the

request of the customer if the customer will pay all

costs; (3) if there are no circumstances under which

operators must install excess flow valves, issue a

report within 30 days of such a determination on the

reason for the determination; and (4) within 18

months, develop standards for the performance of

excess flow valves used to protect lines in natural gas

distribution systems.

Closed: A study found that excess flow valves were not costeffective, and OPS did not require operators to install excess

flow valves. However, 49 C.F.R. 192.383, 2/3/98, addresses

requirements for notifying customers of the availability of excess

flow valves, and 49 C.F.R. 192.381, 6/20/96, addresses

performance standards for the valves.

212 (liquid) Emergency flow restriction devices: (1) Within 2 years,

survey and assess the effectiveness of emergency

flow restriction devices (including remotely controlled

valves and check valves) and other procedures,

systems, and equipment used to detect and locate

pipeline ruptures and minimize product releases from

pipeline facilities; (2) within 2 years after the survey

and assessment, issue regulations prescribing the

circumstances under which operators must use

emergency flow restriction devices and other

procedures, systems, and equipment.

Open: OPS issued a proposed rule to solicit data (59 F.R. 2802,

1/19/94). A study sponsored by the Research and Special

Programs Administration on emergency flow restriction devices

was issued on 9/29/95. A public workshop was held in 10/95.

The American Petroleum Institute’s leak detection practices

were adopted in 49 C.F.R. part 195 on 7/6/98. A proposed rule

to require additional testing, inspection, and remediation of

hazardous liquid pipelines in high-consequence areas was to be

issued by 3/31/00. The American Petroleum Institute is to

develop an industry standard on U.S. areas unusually sensitive

to damage from a pipeline spill, which may help define pipeline

segments, including those in high-consequence areas, that are

candidates for emergency flow restriction devices and other

inspection, testing, and integrity assurance approaches.

Continued
Appendix IV

OPS’ Action on Statutory Requirements,

1988-2000

Page 56 GAO/RCED-00-128 Oversight of Pipeline Safety

106(1) (gas)

205(1) (liquid)

Operator testing: Require testing and certification that

addresses the ability to recognize and appropriately

react to abnormal operating conditions that may

indicate a dangerous situation or a condition

exceeding design limits.

Closed: A final rule, to require all pipeline operations and

maintenance workers to be qualified to perform their tasks and

to be able to recognize and react to abnormal operating

conditions, was published on 8/27/99 (64 F.R. 46853).

Operators must have qualification plans prepared by 4/27/01

and all workers must be qualified by 10/28/02.

107 (gas) Replacement of cast iron pipelines: Publish a notice

as to the availability of industry guidelines for the

replacement of cast iron pipe and, within 2 years after

the guidelines are available, survey operators with

cast iron piping systems to determine the extent to

which each operator has adopted and followed a plan

for the safe management and replacement of cast

iron, the elements of the plan, and the progress that

has been made.

Closed: OPS issued an alert notice (ALN-91-02) reminding all

operators of natural gas distribution systems to have a program

to identify and replace cast iron piping systems that may

threaten public safety. The agency also informed operators of

guidelines and computer programs that were available to help

operators determine the serviceability of cast iron pipe and

schedule its replacement. Cast iron is used exclusively by gas

distribution operators that are regulated under state pipeline

safety programs. Therefore, OPS’ annual auditing of the state

pipeline safety programs ensures that the states are monitoring

distribution pipeline operators’ plans for inspecting, managing,

and replacing cast iron pipe. A survey of cast iron pipe in use by

operators was completed in 1992 and is now being revised.

109(b) (gas)

208(b) (liquid)

Gathering lines: Within 2 years, issue a regulation

defining a “gathering line” and within 3 years, issue a

regulation defining a “regulated gathering line.”

Open: A proposed rule defining a gas gathering line is expected

by mid-2000.

115 (gas) Customer-owned service lines: (1) Within 1 year,

issue regulations requiring operators that do not

maintain customer-owned service lines up to the walls

of customers’ buildings to advise their customers of

the requirements for maintaining those lines; (2) within

18 months, review the Department of Transportation’s

and states’ rules, policies, procedures, and other

measures concerning the safety of customer-owned

service lines and their effectiveness and survey the

owners of customer-owned service lines regarding the

operation and maintenance of such lines; (3) within 2

years, issue a report on the results of the review and

survey; and (4) within 1 year after transmitting the

report, take action to promote the adoption of

measures to improve the safety of such service lines.

Closed: 49 C.F.R. 192.16, 8/14/95, imposes requirements for

notifying customers. The requirement to take action to promote

the adoption of measures to improve the safety of customerowned service lines was eliminated in the Accountable Pipeline

Safety and Partnership Act of 1996 (49 U.S.C. 60113).

108(5) (gas)

207(5) (liquid)

Periodic underwater inspections: Require operators to

conduct periodic inspections of offshore pipelines and

those in navigable waterways; within 2 years, define

what constitutes an exposed underwater pipeline and

what constitutes a hazard to navigation or public

safety.

Open: A proposed rule (based on the Texas A&M University

report’s recommendation for a risk-based approach) is to be

issued by 7/00.

113(a) (gas)

213(a) (liquid)

Opportunity for state comment: Provide to appropriate

state officials in any state in which a pipeline facility is

located notice and an opportunity to comment on any

agreement proposed to be entered into by the

Secretary to resolve a proceeding initiated under this

section with respect to such a pipeline facility.

Closed: OPS provides an opportunity for state officials to

comment before any agreement with a pipeline company is

finalized. This is required by OPS’ enforcement manual.

Section Statutory requirement Status

Continued from Previous Page
Appendix IV

OPS’ Action on Statutory Requirements,

1988-2000

Page 57 GAO/RCED-00-128 Oversight of Pipeline Safety

Source: For columns 1 and 2, GAO’s analysis of pipeline safety statutes; for column 3, status reports

from OPS.

117 (gas)

216 (liquid)

Underwater abandoned pipeline facilities: Identify

what constitutes a hazard to navigation with respect to

underwater abandoned pipeline facilities and, within

18 months, specify the manner in which operators

shall report underwater abandoned pipeline facilities.

Open: A proposed rule was published on 8/30/99 (64 F.R.

47157). The final rule was to be published by 4/00.

206 (liquid) Low internal stress hazardous liquid pipeline facilities:

In exercising discretion, the Secretary shall not

provide an exception to regulation for any pipeline

facility solely on the basis of the fact that such a

pipeline facility operates at low internal stress.

Closed: A final rule, issued on 7/12/94, eliminated an exemption

from regulation based solely on low internal pipe stress (59 F.R.

35465). Subsequently, questions were raised about the

applicability of the rule to very short segments of pipeline

carrying petroleum between plant sites. A proposed rule (63

F.R. 9993, 2/27/98) and a final rule (63 F.R. 46692, 9/2/98)

addressed very short plant lines.

304 One-call enforcement: Establish procedures to notify

the Occupational Safety and Health Administration of

any pipeline accident in which an excavator, by

causing damage to a pipeline, may have violated the

Administration’s regulations.

Closed: OPS monitors telephone reports from pipeline

operators on a daily basis. Any report of an accident involving

damage by an excavator or outside force is reported to the

appropriate Occupational Safety and Health Administration

regional office.

306 Underground utility location technologies: Carry out a

research and development program on these

technologies.

Open: Funding for research on pipeline-locating and -monitoring

technologies is included in OPS’ fiscal year 2001 budget

request as part of the agency’s proposed research program.

The funding is not for a specifically authorized item but is

included as part of OPS’ research plan for preventing excavation

damage.

307 Underwater abandoned pipeline facilities: Undertake a

study of such facilities and, within 3 years, submit a

report to the Congress on the results of the study.

Open: The Research and Special Programs Administration

analyzed the extent and nature of the hazards posed by

underwater abandoned pipelines and surveyed federal policies

and state activities involving abandoned pipelines in navigable

waters. The collected information proved to be insufficient to

fully address the issue. Therefore, the Administration issued a

proposed rule (64 F.R. 47157, 8/30/99) to require the reporting

of abandoned pipelines. The Administration intends to continue

analyzing the hazards posed by abandoned pipelines after it

issues the final rule requiring the reporting of abandoned

pipelines, expected by 6/00.

Section Statutory requirement Status

Continued from Previous Page
Appendix IV

OPS’ Action on Statutory Requirements,

1988-2000

Page 58 GAO/RCED-00-128 Oversight of Pipeline Safety

Table 11: Accountable Pipeline Safety and Partnership Act of 1996 (P.L. 104-304, Oct. 12, 1996)

Section Statutory requirement Status

49 U.S.C.

60101(b)(2)

3(b)

Gathering lines: Amend the requirement to define

“regulated gathering line” by changing “shall” to “shall,

if appropriate.”

Open: OPS is consulting with the gas pipeline industry and

gathering line operators on alternative approaches to clearly

identify gathering lines. A proposed rule is expected by 7/00.

60102(a)

4(a)(2),(3)

Operator qualification: Change a requirement to

ensure that individuals performing operations and

maintenance on pipelines are properly qualified by

replacing the words “test and certify” with “qualified”

and define qualifications to include the ability to

recognize and react appropriately to abnormal

operating conditions.

Closed: A final rule was published on 8/27/99. Operators must

have plans prepared by 4/27/01, and all workers must be

qualified by 10/28/02.

60102(b)

4(b)

Factors for consideration, including risk assessment

and cost/benefit analysis: Clarify requirements to

consider risk assessment, the environment, costbenefit analysis, and the recommendations of

advisory committees when prescribing standards, as

well as a general requirement that standards be

practicable and designed to meet needs for safety and

environmental protection.

Closed: OPS’ cost-benefit analyses were already in compliance

with most of these requirements. In 2/99, OPS published

guidance for cost-benefit analyses, Final Report: A

Collaborative Framework for Office of Pipeline Safety CostBenefit Analyses, developed with input from the pipeline

industry and opportunity for public comment. The advisory

committees are acting as “peer reviewers” for all risk

assessments and cost-benefit analyses prepared by OPS to

support rulemaking actions. OPS provided the advisory

committees with training in risk assessment and pipeline

technologies to enable the committees to fulfill their roles.

60102(b)(7)

4(b)

Risk assessment: Not later than 3/31/00, transmit to

the Congress a report that (1) describes the

implementation of the act’s risk assessment

requirements and (2) includes any recommendations

that would make the risk assessment process a more

effective means of assessing the benefits and costs

associated with alternative regulatory and

nonregulatory options in prescribing standards.

Open: OPS provided an interim report, Beyond Compliance:

Creating a Responsible Regulatory Environment that Promotes

Excellence, Innovation, and Efficiency: A Progress Report on

the Pipeline Risk Management Demonstration Program, to the

Congress and the public in 5/99. The agency is now clearing a

final report for issuance.

60102(f)(1)

4(e)

Standards on accommodating smart pigs: Require

new and replacement natural gas transmission and

hazardous liquid pipelines to accommodate “smart

pigs”; allow the extension of such standards to

existing pipelines.

Open for certain pipelines: A final rule was published (59 F.R.

17275, 4/12/94). Notice 2 (59 F.R. 49896, 9/30/94) extended the

compliance date for existing gas transmission lines and

modified the requirement for offshore and rural gas transmission

lines. Notice 3 (60 F.R. 7133, 2/7/95) suspended OPS’

enforcement of the final rule’s requirements for modifications of

sections of onshore gas transmission lines and for new and

existing offshore gas transmission lines. A final rule addressing

a petition for reconsideration is being prepared for publication in

5/00.

60102(f)(2)

4(e)

Periodic inspections: Modify the requirement for the

Secretary to prescribe periodic inspections of each

pipeline identified in high-density and environmentally

sensitive areas by inserting “if necessary, additional”

after “shall prescribe.”

Open: A proposed rule to require periodic inspections of

hazardous liquid pipelines in high-consequence areas was

issued on 4/24/00.

Continued
Appendix IV

OPS’ Action on Statutory Requirements,

1988-2000

Page 59 GAO/RCED-00-128 Oversight of Pipeline Safety

60102(l)

4(f)

Updating standards: To the extent appropriate and

practicable, update the standards incorporated by the

industry that have been adopted as part of the federal

pipeline safety regulatory program.

Open: OPS planned to issue a proposed rule in 12/99.

60102(c)(4)

4(g)

Promoting public awareness: (1) By 6/1/98, survey

and assess certain public education and public safety

programs and determine their effectiveness; (2) not

later than 1 year after the survey and assessment are

completed, institute a rulemaking to determine the

most effective components of a public safety and

education program and promulgate, if appropriate,

standards implementing these components on a

nationwide basis; (3) if the promulgation of such

standards is not appropriate, report to the Congress

the reasons for that finding.

Closed: A survey of damage prevention programs was

completed in 1998, and a damage prevention pilot project has

been completed in three states. OPS is working with the

pipeline industry to evaluate existing public education programs.

In 6/99, OPS “rolled out” a national promotional campaign.

60102(j)(3)

4(b)

Remotely controlled valves: (1) By 6/1/98, survey and

assess the effectiveness of remotely controlled valves

to shut off the flow of natural gas in the event of a

rupture and (2) determine whether the use of remotely

controlled valves is technically and economically

feasible and would reduce the risks associated with a

rupture; (3) within 1 year of completing the survey and

assessment, if the use of valves is feasible and would

reduce risks, prescribe standards for the use of these

valves, including requirements for their use in densely

populated areas.

Open: OPS published a report in 9/99 concluding that remotely

controlled valves are technically, but not economically, feasible.

At a public meeting on 11/4/99, OPS proposed that criteria,

such as a definitive time to shut off a ruptured section in a highconsequence area, be considered. This issue will be considered

further after high-consequence areas for gas transmission

pipelines are defined.

60109(b)

7(b)

Unusually sensitive areas: Change language from

“shall include” to “shall consider” under areas to be

included as unusually sensitive; add drinking water

and wildlife resources as considerations; and delete

earthquakes and other ground movement as

considerations.

Open: A proposed rule on the definition of unusually sensitive

areas was issued (64 F.R. 73464, 12/30/99). (Comments are

due on 6/27/00.)

60110(b)(4)

8(2)

Excess flow valves: Consider the costs of operation

and maintenance in promulgating regulations

requiring excess flow valves.

Closed: OPS adopted performance standards for excess flow

valves and issued a rule requiring that customers be notified of

the availability of such valves.

60126

5(a)

Risk management: Establish risk management

demonstration projects and report on the results of

such projects by 3/31/00.

Open: These projects are ongoing; OPS was preparing a final

report for publication by 4/30/00.

60124

15(2)

Biennial reports: Not later than 8/15/97 and every

2 years thereafter, submit to the Congress a report on

how this chapter was carried out during the

2 immediately preceding calendar years for gas and

hazardous liquids.

Open: The first report was issued in 8/97; the next report was

due in 8/99.

Section Statutory requirement Status

Continued from Previous Page
Appendix IV

OPS’ Action on Statutory Requirements,

1988-2000

Page 60 GAO/RCED-00-128 Oversight of Pipeline Safety

Source: For columns 1 and 2, GAO’s analysis of pipeline safety statutes; for column 3, status reports

from OPS.

Table 12: Transportation Equity Act for the 21st Century (P.L. 105-178, June 9, 1998)

Source: For columns 1 and 2, GAO’s analysis of pipeline safety statutes; for column 3, status reports

from OPS.

60127(a)

16(a)

Population encroachment: (1) Make available to each

state the land-use recommendations in the

Transportation Research Board’s special report

entitled Pipelines and Public Safety (No. 219);

(2) evaluate the recommendations, determine the

extent to which they are being implemented, consider

ways to improve their implementation, and consider

other initiatives to make local planning and zoning

entities more aware of issues involving the

encroachment of population along pipeline rights-ofway.

Open: OPS sent the Transportation Research Board’s report to

all states. An evaluation was to be prepared and published in

early 2000.

60301(nt)

17

User fee assessment: Within 1 year, transmit to the

Congress a report analyzing the present assessment

of pipeline safety user fees solely on the basis of

mileage to determine whether this or another measure

would be more appropriate.

Closed: A draft report was approved by the pipeline safety

advisory committees in 5/97. A final report was prepared and

submitted to Congress in 3/98.

Section Statutory requirement Status

Continued from Previous Page

Section Statutory requirement Status

7302(a)

49 U.S.C. 6105

One-call notification systems: If information is readily

available, undertake a study of damage prevention

practices associated with existing one-call notification

systems and, within 1 year of enactment of this

chapter, publish a report on the practices that are

most and least successful.

Closed: A study of best practices to prevent damage to

underground facilities, Common Ground: Study of One-Call

Systems and Damage Prevention Best Practices, was published

in 8/99. More than 160 government employees and

underground facility operators contributed to the report. Followup action to establish a foundation for implementing the

recommendations and best practices is now being established.
Page 61 GAO/RCED-00-128 Oversight of Pipeline Safety

Appendix V

GAO Contacts and Staff Acknowledgements ApendxiV

GAO Contacts Phyllis F. Scheinberg (202) 512-3650

James Ratzenberger (202) 512-3650

Acknowledgements In addition to those named above, Sumikatsu Arima, Ryan T. Coles, Helen

Desaulniers, Deena Richart, and Sara Vermillion made key contributions to

this report.

(348187) Letr
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