Pipeline Safety: The Office of Pipeline Safety Is Changing How It
Oversees the Pipeline Industry (Letter Report, 05/15/2000,
GAO/RCED-00-128).

Pursuant to a congressional request, GAO reviewed the Department of
Transportation Office of Pipeline Safety's (OPS) performance in
regulating pipeline safety, focusing on: (1) the extent of major
pipeline accidents from 1989 through 1998; (2) OPS' implementation of
the 1996 Accountable Pipeline Safety and Partnership Act's risk
management demonstration program; (3) OPS' inspection and enforcement
efforts since the act's implementation; and (4) OPS' responsiveness to
recommendations from the National Transportation Safety Board and to
statutory requirements designed to improve pipeline safety.

GAO noted that: (1) from 1989 through 1998, pipeline accidents resulted
in an average of about 22 fatalities per year; (2) 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; (3) most fatalities and injuries
occurred as a result of accidents on pipelines that transport natural
gas to homes and businesses, while most property damage occurred as a
result of accidents on pipelines transporting hazardous liquids; (4)
OPS's data indicate that damage from outside forces, such as excavation,
is the primary cause of such accidents; (5) OPS has implemented a risk
management demonstration program and has approved six demonstration
projects; (6) OPS 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; (7) even though the projects are not complete and their safety
benefits have not been quantified, OPS is moving ahead with a risk-based
approach to safety regulation based partially on preliminary qualitative
results of the program; (8) specifically, OPS has proposed a rule that
would require some companies that operate hazardous liquid pipelines
that run through high-risk areas 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; (9) OPS also plans to take several actions that are necessary
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; (10) since the act's implementation, OPS has modified its
inspection and enforcement approach so that entire pipelines are
inspected in order to provide a comprehensive assessment of safety
risks; (11) OPS has revised its enforcement of compliance with
regulations by reducing its use of fines, and instead, working with
operators to identify and correct safety problems; (12) OPS has not
implemented some of the Safety Board's recommendations and requirements
because it believes they would be too costly for the pipeline industry
compared with the expected benefits; and (13) the OPS has recently taken
action on some issues covered by outstanding recommendations and
requirements, such as identifying countermeasures for preventing damage
to pipelines from excavation and requiring pipeline operators to inspect
their pipelines for corrosion.

--------------------------- Indexing Terms -----------------------------

 REPORTNUM:  RCED-00-128
     TITLE:  Pipeline Safety: The Office of Pipeline Safety Is Changing
	     How It Oversees the Pipeline Industry
      DATE:  05/15/2000
   SUBJECT:  Pipeline operations
	     Transportation industry
	     Transportation safety
	     Hazardous substances
	     Gas pipeline operations
	     Accident prevention
	     Inspection
	     Performance measures
IDENTIFIER:  Bellingham (WA)
	     DOT Risk Demonstration Program

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GAO/RCED-00-128

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

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

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

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

OPS Office of Pipeline Safety

DOT Department of Transportation

Resources, Community, and
Economic Development Division

B-283653

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 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.

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 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
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.

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.

ï¿½ Natural gas transmission pipelines transport natural gas over long
distances from sources to communities. These pipelines--about
325,000 miles--are primarily interstate.

ï¿½ 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.

ï¿½ 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.

Figure 1: Components of Natural Gas Transmission and Distribution Pipelines
Source: Office of Pipeline Safety.

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.

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.

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 ton-mile of oil transported for all other modes is
typically at least twice--and in 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

 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

aThe 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.

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 because the
liquids do not dissipate into the atmosphere, as does natural gas.

Figure 3: Number of Fatalities and Injuries and Amount of Property Damage
From Pipeline Accidents, 1989-98
Source: GAO's analysis of OPS' data.

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.)

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.

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).

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.

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 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.)

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 project-specific
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 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.

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 high-consequence
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 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

 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    OPS hires and trains additional staff to review
 2000                 companies' integrity management programs
                      OPS completes the final rule on the definition of
 December 2000        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

Source: GAO's analysis of OPS' data.

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.

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.

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
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.

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.

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.

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.)

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 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.

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 designed to improve
pipeline safety. OPS has not implemented 22 of these requirements, 12 of
which date from 1992 and prior years.

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

Table 3: Transportation Agencies' Implementation Rates for Safety Board
Recommendations, 1967-99

 Transportation agency         Total number of        Implementation rate
                               recommendations        (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              243                    69
 Administration)
 Total/average rate            6,829                  81

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:

ï¿½ 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 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- 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.

ï¿½ 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.

ï¿½ 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 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.

ï¿½ 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.

ï¿½ 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.

ï¿½ 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.

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 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

                                  Total                Number of
                                  number of            requirements
 Legislation                      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

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 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.

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.

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 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.

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, 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.

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 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.

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

The Bellingham, Washington, Pipeline Accident

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.

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.

Figure 7: Location of Olympic Pipe Line Rupture
Source: National Transportation Safety Board.

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.

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.

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.

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, 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.

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 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.

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.

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.

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
Seattle-Tacoma Airport.

Maps of Natural Gas Transmission and Hazardous Liquid Pipelines

Figure 8: Locations of Natural Gas Transmission Pipelines
Source: OPS, based on data from MAPSearch Services.

Figure 9: Locations of Hazardous Liquid Pipelines
Source: OPS, based on data from MAPSearch Services.

Status of Risk Management Demonstration Projects

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

 Operator       Regions        Project focus                   Date
                affected                                       approved
                               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
 Equilon                       pipeline segments, Equilon is
 Pipeline       Southwest      developing a comprehensive      March 1998
                               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.
                               Exxon Mobil is demonstrating
                               its release prevention (tank
                               integrity) program at its
                               crude oil breakout facility in
 Exxon Mobil    Central        Patoka, Illinois. The project   August 1998
                               will examine how Exxon Mobil's
                               release prevention measures
                               will work in conjunction with
                               OPS' proposed standards for
                               aboveground storage tanks.
                               Phillips is using risk
                               management along a 60-mile
                               segment of both an
                               18-inch and a 12-inch refined
 Phillips Pipe                 oil products pipeline. The
 Line Company   Southwest      project will explore ways of    August 1998
                               minimizing the risks
                               associated with excavation
                               work along the pipelines to
                               reduce or eliminate damage
                               from outside forces.
                               The company is incorporating
                               risk management into a
                               13,000-mile natural gas
                               pipeline system. It hopes to
 Kinder Morgan, Central,       form a comprehensive risk       December
 Inc.           Southwest      management program based on     1998
                               existing company programs such
                               as pipeline integrity,
                               regulatory compliance
                               management, and emergency
                               response.
                               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
 Chevron Pipe                  pipelines, one transporting     February
 Line           Western        gasoline and the other          1999
                               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.
                               Northwest is developing a risk
                               management program for its
                               entire
                               3,900-mile natural gas system.
                               The project will explore means
 Northwest                     of assessing and addressing
 Pipeline       Western        risks presented by a pipeline   January 2000
                               in rugged terrain susceptible
                               to land movement and
                               investigate the risk-reduction
                               benefits of certain new
                               technologies.

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
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

                                 Fiscal year
 Description   1996       1997      1998       1999       2000      Total
 Federal
 salary and $355,000   $363,000   $379,000   $393,000  $425,000   $1,915,000
 benefitsa
 Estimated
 travel     200,000    200,000    200,000    200,000   200,000    1,000,000
 costs
 Contractor
 support    1,249,956  1,069,053  811,599    708,346   900,000b   4,738,954
 costs
 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

aEstimated salary and benefits for five full-time equivalent employees per
year.

bAccording 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.

OPS' Action on Statutory Requirements,
1988-2000

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)

Continued from Previous Page

    Section        Statutory requirement                 Status
                                             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
               Reporting standards: Within 1 pipelines and their
               year, establish standards for environment. OPS and the
               operators to provide          states are now receiving data
               information, including the    from the pipeline companies.
 102 (gas)     following: Name, address,
 202 (liquid)  phone number; Map; Pipeline   In addition, OPS is working
               characteristics; Description  with the hazardous liquid
               of products transported;      pipeline industry to develop a
               Operations manual; Emergency  voluntary annual report that
               response plan.                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.
                                             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
               Pipeline inventory: Establish hazardous liquid pipeline
               standards to require          industry pilot-tested a system
               operators, within 1 year, to  to assess the effects of the
 102 (gas)     complete and maintain an      team's data collection
 202 (liquid)  inventory of all types of     recommendations; an analysis
               pipe used, including the      of the results will soon be
               materials used and a history  completed. Pipe inventory
               of any leaks.                 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.
                                             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
               Accident coordination: Within through memorandums of
               1 year, establish procedures  understanding, letters of
 105(2) (gas)  to more effectively           agreement, and informal
 209 (liquid)  coordinate the response of    undertakings. Parts 192 and
               federal agencies and the      195 both require pipeline
               states to pipeline accidents. 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.
               Inspection frequency: Inspect
               and, as appropriate, require
               the testing of pipeline
               facilities at specified
               intervals, but no less
               frequently than once every    Closed: The Accountable
 108(a)(2)     2 years; master meter         Pipeline Safety and
 (gas)         operators can be inspected    Partnership Act of 1996 (49
 207(a)        less frequently; the          U.S.C. 60108(b)) eliminated
 (liquid)      frequency and type of         the requirement for testing at
               inspections shall be          2-year intervals.
               determined on a case-by-case
               basis, considering factors
               such as location,
               characteristics, and
               materials transported.
                                             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
               Smart pig accommodation:      offshore and rural gas
 108(b) (gas)  Establish standards requiring transmission lines. Notice 3
 207(b)        that new and replacement pipe (60 F.R. 7133, 2/7/95)
 (liquid)      shall accommodate the passage suspended enforcement of the
               of smart pigs.                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.
                                             Open: A final report, An
                                             Analysis of Natural Gas Master
                                             Meter Systems (Definition and
                                             Program) from a Federal
               Master meter study: Assess    Perspective, was issued
               the need for an improved      6/15/79. An additional study
 108(c)(gas)   inspection program for master on master meter systems was
               meter systems and issue a     drafted following a survey of
               report within 18 months.      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.
               Carbon dioxide: Regulate
               carbon dioxide transported by
 211(a)        pipeline and amend            Closed: 49 C.F.R. part 195 was
 (liquid)      regulations as appropriate to amended for carbon dioxide on
               ensure the safe               6/21/91.
               transportation of carbon
               dioxide by pipeline.
               One-call systems: Within 18   Closed: 49 C.F.R. 198, Subpart
               months, issue regulations     C, 9/20/90 addresses one-call
               establishing minimum federal  notification; also, 49 C.F.R.
 303(a)        requirements for establishing 192.614 and 49 C.F.R. 195.442,
               and operating one-call        11/19/97, mandate states'
               notification systems for      participation in one-call
               adoption by states.           systems.
               Smart pig feasibility study:
               Assess the feasibility of
               requiring the inspection of   Closed: OPS issued a report,
 304           transmission facilities with  Instrumented Internal
               smart pigs at periodic        Inspection Devices, in 11/92.
               intervals and issue a report
               within 18 months.
               Emergency flow valve
               feasibility study: Study the  Closed: A study sponsored by
               safety, cost, feasibility,    the Research and Special
 305           and effectiveness of          Programs Administration,
               requiring operators to        Emergency Flow Restricting
               install emergency             Devices Study, was issued in
               flow-restricting devices and  3/91.
               issue a report within 1 year.
               Feasibility of regulating
               excavation activity: Assess
               the feasibility of regulating Closed: A report, Examination
 306           persons whose excavation      of the Feasibility of
               activities may result in      Regulating Excavators, was
               damage to pipeline facilities issued in 10/90.
               and issue a report within 1
               year.

Source: For columns 1 and 2, GAO's analysis of pipeline safety statutes; for
column 3, status reports from OPS.

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

 Section         Statutory requirement       Status
                                             Closed: An interim final rule
                                             on onshore facilities was
                 Response plans for onshore  published (58 F.R. 244,
                                             1/5/93). Response plans have
 4202(a)(6),     oil pipelines: Issue        been submitted under this
 (b)(4)          regulations for oil spill   interim rule. The final rule,
                 response plans for onshore
                 oil pipelines by 8/18/92.   incorporating experience in
                                             operating spill response
                                             systems and reviewing plans,
                                             is to be issued in 5/00.

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)

Continued from Previous Page

   Section      Statutory requirement                  Status
             Reporting standards: Within
 1(a) (gas)  6 months of 11/16/90,
 1(b)        establish standards defining Closed: 49 C.F.R. 192.3 and 195.2
 (liquid)    "exposed pipeline facility"  define these terms.
             and "hazard to navigation."
                                          Closed: 49 C.F.R. 191.27,
             Hazardous conditions:        192.612, 195.57, and 195.413
             Establish, by regulation, a  specify reporting procedures for
             program requiring operators  pipelines in the Gulf of Mexico
             of offshore and navigable    and its inlets. In addition, OPS
 1(a) (gas)  water pipelines to report    issued alert notices to the
 1(b)        potential or existing        offshore fishing industry
 (liquid)    navigational hazards         (ALN-90-01) warning of hazards to
             involving pipeline           fishing vessels from exposed
             facilities to the Secretary  pipelines and to Gulf of Mexico
             through the Coast Guard (as  operators (ALN-98-03) warning of
             enacted, limited to the Gulf the possibility of exposed
             of Mexico and its inlets).   pipelines after Hurricane
                                          Georges.

             Permanent inspections:       Open: OPS signed a memorandum of
             Establish an inspection      understanding with the Minerals
                                          Management Service to define
 1(a) (gas)  program for offshore and     inspection responsibilities for
 1(b)        navigable water pipelines no offshore pipelines. A proposed
 (liquid)    later than 30 months after   rule for periodic underwater
             11/16/90 (as enacted,
             limited to the Gulf of       pipeline inspections is now being
             Mexico and its inlets).      prepared for publication by
                                          mid-2000.
             Burial: Require, by
             regulation, that exposed or
             hazardous pipelines be
 1(a) (gas)  buried within 6 months after Closed: 49 C.F.R. 192.612 and
 1(b)        the date that the condition  195.413 impose requirements for
 (liquid)    of the pipeline is reported  pipelines in the Gulf of Mexico
             to the Secretary (unless the and its inlets.
             Secretary extends the time
             period for compliance).
                                          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
             Navigational hazards:        (ALN-90-01) warning of hazards to
             Establish a program to       fishing vessels from exposed
             encourage fishermen and      pipelines and to Gulf of Mexico
             other vessel operators to    operators (ALN-98-03) warning of
 2           report potential or existing the possibility of exposed
             navigational hazards         pipelines after Hurricane
             involving pipelines to the   Georges. Fishermen in the Gulf of
             Secretary through Coast      Mexico now voluntarily provide
             Guard field offices.         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.
                                          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,
             Study: Study several issues  issued in 1/98. The study
             related to underwater        recommended that OPS (1)
 3           pipelines and report to the  establish regulations requiring
             Congress on the results of   the inspection of pipelines to
             actions no later than 6      determine their depth of burial
             months after 11/16/90.       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.

Source: For columns 1 and 2, GAO's analysis of pipeline safety statutes; for
column 3, status reports from OPS.

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

Continued from Previous Page

   Section        Statutory requirement                  Status
                                             Open: On 4/24/00, OPS issued a
                                             proposed rule requiring
                                             additional testing,
              High-density population areas  inspection, and remediation of
              (for gas and liquid) and       hazardous liquid pipelines in
              environmentally sensitive      high-consequence areas. The
 102(a)(2)    areas (for liquid): Within 2   agency issued, on 12/30/99, a
 (gas)        years, issue regulations       proposed rule defining U.S.
 202(a)(2)    establishing criteria for the  areas unusually sensitive to
 (liquid)     identification of all pipeline environmental damage (64 F.R.
              facilities that are located in 73464). (Comments are due on
              high-density and               6/27/00). An additional
              environmentally sensitive      proposed rule for the
              areas.                         inspection and testing of gas
                                             transmission pipelines in
                                             high-consequence areas will be
                                             issued in 2000.
              Update inspections/smart pigs:
              Within 3 years, issue
              regulations requiring the
              periodic inspection of
              pipelines in high-density and
              environmentally sensitive
                                             Open: A proposed rule to
 103(5) (gas) areas, specifying the          require periodic inspections
 203(5)       circumstances, if any, under   of hazardous liquid pipelines
 (liquid)     which inspections should be    in high-consequence areas was
              conducted using smart pigs;
              when smart pigs are not        issued on 4/24/00.
              required, require an
              inspection method that is at
              least as effective in
              providing for the safety of
              the pipeline.
              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 Closed: A study found that
              do not require but can         excess flow valves were not
              accommodate excess flow valves cost-effective, and OPS did
              that such valves shall be      not require operators to
              installed at the request of    install excess flow valves.
 104 (gas)    the customer if the customer   However, 49 C.F.R. 192.383,
              will pay all costs; (3) if     2/3/98, addresses requirements
              there are no circumstances     for notifying customers of the
              under which operators must     availability of excess flow
              install excess flow valves,    valves, and 49 C.F.R. 192.381,
              issue a report within 30 days  6/20/96, addresses performance
              of such a determination on the standards for the valves.
              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.
                                             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
              Emergency flow restriction     flow restriction devices was
              devices: (1) Within 2 years,   issued on 9/29/95. A public
              survey and assess the          workshop was held in 10/95.
              effectiveness of emergency     The American Petroleum
              flow restriction devices       Institute's leak detection
              (including remotely controlled practices were adopted in 49
              valves and check valves) and   C.F.R. part 195 on 7/6/98. A
              other procedures, systems, and proposed rule to require
              equipment used to detect and   additional testing,
 212 (liquid) locate pipeline ruptures and   inspection, and remediation of
              minimize product releases from hazardous liquid pipelines in
              pipeline facilities; (2)       high-consequence areas was to
              within 2 years after the       be issued by 3/31/00. The
              survey and assessment, issue   American Petroleum Institute
              regulations prescribing the    is to develop an industry
              circumstances under which      standard on U.S. areas
              operators must use emergency   unusually sensitive to damage
              flow restriction devices and   from a pipeline spill, which
              other procedures, systems, and may help define pipeline
              equipment.                     segments, including those in
                                             high-consequence areas, that
                                             are candidates for emergency
                                             flow restriction devices and
                                             other inspection, testing, and
                                             integrity assurance
                                             approaches.
                                             Closed: A final rule, to
                                             require all pipeline
              Operator testing: Require      operations and maintenance
              testing and certification that workers to be qualified to
              addresses the ability to       perform their tasks and to be
 106(1) (gas) recognize and appropriately    able to recognize and react to
 205(1)       react to abnormal operating    abnormal operating conditions,
 (liquid)     conditions that may indicate a was published on 8/27/99 (64
              dangerous situation or a       F.R. 46853). Operators must
              condition exceeding design     have qualification plans
              limits.                        prepared by 4/27/01 and all
                                             workers must be qualified by
                                             10/28/02.
                                             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
              Replacement of cast iron       public safety. The agency also
              pipelines: Publish a notice as informed operators of
              to the availability of         guidelines and computer
              industry guidelines for the    programs that were available
              replacement of cast iron pipe  to help operators determine
              and, within 2 years after the  the serviceability of cast
              guidelines are available,      iron pipe and schedule its
                                             replacement. Cast iron is used
 107 (gas)    survey operators with cast     exclusively by gas
              iron piping systems to
              determine the extent to which  distribution operators that
              each operator has adopted and  are regulated under state
              followed a plan for the safe   pipeline safety programs.
              management and replacement of  Therefore, OPS' annual
              cast iron, the elements of the auditing of the state pipeline
              plan, and the progress that    safety programs ensures that
              has been made.                 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.
              Gathering lines: Within 2
 109(b) (gas) years, issue a regulation      Open: A proposed rule defining
 208(b)       defining a "gathering line"    a gas gathering line is
 (liquid)     and within 3 years, issue a    expected by mid-2000.
              regulation defining a
              "regulated gathering line."
              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   Closed: 49 C.F.R. 192.16,
              the Department of              8/14/95, imposes requirements
              Transportation's and states'   for notifying customers. The
              rules, policies, procedures,   requirement to take action to
              and other measures concerning  promote the adoption of
 115 (gas)    the safety of customer-owned   measures to improve the safety
              service lines and their        of customer-owned service
              effectiveness and survey the   lines was eliminated in the
              owners of customer-owned       Accountable Pipeline Safety
              service lines regarding the    and Partnership Act of 1996
              operation and maintenance of   (49 U.S.C. 60113).
              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.
              Periodic underwater
              inspections: Require operators
              to conduct periodic
              inspections of offshore        Open: A proposed rule (based
 108(5) (gas) pipelines and those in         on the Texas A&M University
 207(5)       navigable waterways; within 2  report's recommendation for a
 (liquid)     years, define what constitutes risk-based approach) is to be
              an exposed underwater pipeline issued by 7/00.
              and what constitutes a hazard
              to navigation or public
              safety.
              Opportunity for state comment:
              Provide to appropriate state
              officials in any state in
              which a pipeline facility is   Closed: OPS provides an
                                             opportunity for state
 113(a) (gas) located notice and an          officials to comment before
 213(a)       opportunity to comment on any  any agreement with a pipeline
 (liquid)     agreement proposed to be       company is finalized. This is
              entered into by the Secretary
              to resolve a proceeding        required by OPS' enforcement
              initiated under this section   manual.
              with respect to such a
              pipeline facility.
              Underwater abandoned pipeline
              facilities: Identify what
              constitutes a hazard to
              navigation with respect to     Open: A proposed rule was
 117 (gas)    underwater abandoned pipeline  published on 8/30/99 (64 F.R.
 216 (liquid) facilities and, within 18      47157). The final rule was to
              months, specify the manner in  be published by 4/00.
              which operators shall report
              underwater abandoned pipeline
              facilities.
                                             Closed: A final rule, issued
                                             on 7/12/94, eliminated an
              Low internal stress hazardous  exemption from regulation
              liquid pipeline facilities: In based solely on low internal
              exercising discretion, the     pipe stress (59 F.R. 35465).
              Secretary shall not provide an Subsequently, questions were
 206 (liquid) exception to regulation for    raised about the applicability
              any pipeline facility solely   of the rule to very short
              on the basis of the fact that  segments of pipeline carrying
              such a pipeline facility       petroleum between plant sites.
              operates at low internal       A proposed rule (63 F.R. 9993,
              stress.                        2/27/98) and a final rule (63
                                             F.R. 46692, 9/2/98) addressed
                                             very short plant lines.

              One-call enforcement:          Closed: OPS monitors telephone
              Establish procedures to notify reports from pipeline
              the Occupational Safety and    operators on a daily basis.
              Health Administration of any   Any report of an accident
 304          pipeline accident in which an  involving damage by an
              excavator, by causing damage   excavator or outside force is
              to a pipeline, may have        reported to the appropriate
              violated the Administration's  Occupational Safety and Health
              regulations.                   Administration regional
                                             office.
                                             Open: Funding for research on
                                             pipeline-locating and
                                             -monitoring technologies is
              Underground utility location   included in OPS' fiscal year
                                             2001 budget request as part of
 306          technologies: Carry out a      the agency's proposed research
              research and development
              program on these technologies. program. The funding is not
                                             for a specifically authorized
                                             item but is included as part
                                             of OPS' research plan for
                                             preventing excavation damage.
                                             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
              Underwater abandoned pipeline  navigable waters. The
              facilities: Undertake a study  collected information proved
                                             to be insufficient to fully
 307          of such facilities and, within address the issue. Therefore,
              3 years, submit a report to
              the Congress on the results of the Administration issued a
              the study.                     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.

Source: For columns 1 and 2, GAO's analysis of pipeline safety statutes; for
column 3, status reports from OPS.

Table 11: Accountable Pipeline Safety and Partnership Act of 1996 (P.L.
104-304, Oct. 12, 1996)

Continued from Previous Page

    Section         Statutory requirement                Status
                                              Open: OPS is consulting with
                 Gathering lines: Amend the   the gas pipeline industry and
 49 U.S.C.       requirement to define        gathering line operators on
 60101(b)(2)     "regulated gathering line"   alternative approaches to
 3(b)            by changing "shall" to       clearly identify gathering
                 "shall, if appropriate."     lines. A proposed rule is
                                              expected by 7/00.
                 Operator qualification:
                 Change a requirement to
                 ensure that individuals
                 performing operations and
                 maintenance on pipelines are Closed: A final rule was
                 properly qualified by        published on 8/27/99.
 60102(a)        replacing the words "test    Operators must have plans
 4(a)(2),(3)     and certify" with            prepared by 4/27/01, and all
                 "qualified" and define       workers must be qualified by
                 qualifications to include    10/28/02.
                 the ability to recognize and
                 react appropriately to
                 abnormal operating
                 conditions.
                                              Closed: OPS' cost-benefit
                                              analyses were already in
                                              compliance with most of these
                                              requirements. In 2/99, OPS
                 Factors for consideration,   published guidance for
                 including risk assessment    cost-benefit analyses, Final
                 and cost/benefit analysis:   Report: A Collaborative
                 Clarify requirements to      Framework for Office of
                 consider risk assessment,    Pipeline Safety Cost-Benefit
                 the environment,             Analyses, developed with
                                              input from the pipeline
 60102(b)        cost-benefit analysis, and   industry and opportunity for
 4(b)            the recommendations of       public comment. The advisory
                 advisory committees when
                 prescribing standards, as    committees are acting as
                 well as a general            "peer reviewers" for all risk
                 requirement that standards   assessments and cost-benefit
                 be practicable and designed  analyses prepared by OPS to
                 to meet needs for safety and support rulemaking actions.
                 environmental protection.    OPS provided the advisory
                                              committees with training in
                                              risk assessment and pipeline
                                              technologies to enable the
                                              committees to fulfill their
                                              roles.
                 Risk assessment: Not later
                 than 3/31/00, transmit to
                 the Congress a report that   Open: OPS provided an interim
                 (1) describes the            report, Beyond Compliance:
                 implementation of the act's  Creating a Responsible
                 risk assessment requirements Regulatory Environment that
                 and (2) includes any         Promotes Excellence,
 60102(b)(7)     recommendations that would   Innovation, and Efficiency: A
 4(b)            make the risk assessment     Progress Report on the
                 process a more effective     Pipeline Risk Management
                 means of assessing the       Demonstration Program, to the
                 benefits and costs           Congress and the public in
                 associated with alternative  5/99. The agency is now
                 regulatory and nonregulatory clearing a final report for
                 options in prescribing       issuance.
                 standards.
                                              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
                 Standards on accommodating   lines and modified the
                 smart pigs: Require new and  requirement for offshore and
                 replacement natural gas      rural gas transmission lines.
                                              Notice 3 (60 F.R. 7133,
 60102(f)(1)     transmission and hazardous   2/7/95) suspended OPS'
 4(e)            liquid pipelines to          enforcement of the final
                 accommodate "smart pigs";
                 allow the extension of such  rule's requirements for
                 standards to existing        modifications of sections of
                 pipelines.                   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.
                 Periodic inspections: Modify
                 the requirement for the
                 Secretary to prescribe
                 periodic inspections of each Open: A proposed rule to
 60102(f)(2)     pipeline identified in       require periodic inspections
 4(e)            high-density and             of hazardous liquid pipelines
                 environmentally sensitive    in high-consequence areas was
                 areas by inserting "if       issued on 4/24/00.
                 necessary, additional" after
                 "shall prescribe."
                 Updating standards: To the
                 extent appropriate and
                 practicable, update the
 60102(l)        standards incorporated by    Open: OPS planned to issue a
 4(f)            the industry that have been  proposed rule in 12/99.
                 adopted as part of the
                 federal pipeline safety
                 regulatory program.
                 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 Closed: A survey of damage
                 and assessment are           prevention programs was
                 completed, institute a       completed in 1998, and a
                 rulemaking to determine the  damage prevention pilot
 60102(c)(4)     most effective components of project has been completed in
 4(g)            a public safety and          three states. OPS is working
                 education program and        with the pipeline industry to
                 promulgate, if appropriate,  evaluate existing public
                 standards implementing these education programs. In 6/99,
                 components on a nationwide   OPS "rolled out" a national
                 basis; (3) if the            promotional campaign.
                 promulgation of such
                 standards is not
                 appropriate, report to the
                 Congress the reasons for
                 that finding.
                 Remotely controlled valves:
                 (1) By 6/1/98, survey and
                 assess the effectiveness of
                 remotely controlled valves   Open: OPS published a report
                 to shut off the flow of      in 9/99 concluding that
                 natural gas in the event of  remotely controlled valves
                 a rupture and (2) determine  are technically, but not
                 whether the use of remotely  economically, feasible. At a
                 controlled valves is         public meeting on 11/4/99,
 60102(j)(3)     technically and economically OPS proposed that criteria,
 4(b)            feasible and would reduce    such as a definitive time to
                 the risks associated with a  shut off a ruptured section
                 rupture; (3) within 1 year   in a high-consequence area,
                 of completing the survey and be considered. This issue
                 assessment, if the use of    will be considered further
                 valves is feasible and would after high-consequence areas
                 reduce risks, prescribe      for gas transmission
                 standards for the use of     pipelines are defined.
                 these valves, including
                 requirements for their use
                 in densely populated areas.
                 Unusually sensitive areas:
                 Change language from "shall
                 include" to "shall consider" Open: A proposed rule on the
                 under areas to be included   definition of unusually
 60109(b)        as unusually sensitive; add  sensitive areas was issued
 7(b)            drinking water and wildlife  (64 F.R. 73464, 12/30/99).
                 resources as considerations; (Comments are due on
                 and delete earthquakes and   6/27/00.)
                 other ground movement as
                 considerations.

                 Excess flow valves: Consider Closed: OPS adopted
                                              performance standards for
 60110(b)(4)     the costs of operation and   excess flow valves and issued
 8(2)            maintenance in promulgating  a rule requiring that
                 regulations requiring excess
                 flow valves.                 customers be notified of the
                                              availability of such valves.
                 Risk management: Establish
                                              Open: These projects are
 60126           risk management              ongoing; OPS was preparing a
 5(a)            demonstration projects and   final report for publication
                 report on the results of
                 such projects by 3/31/00.    by 4/30/00.
                 Biennial reports: Not later
                 than 8/15/97 and every
                 2 years thereafter, submit
 60124           to the Congress a report on  Open: The first report was
 15(2)           how this chapter was carried issued in 8/97; the next
                 out during the               report was due in 8/99.
                 2 immediately preceding
                 calendar years for gas and
                 hazardous liquids.
                 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             Open: OPS sent the
                 recommendations, determine   Transportation Research
 60127(a)        the extent to which they are Board's report to all states.
 16(a)           being implemented, consider  An evaluation was to be
                 ways to improve their        prepared and published in
                 implementation, and consider early 2000.
                 other initiatives to make
                 local planning and zoning
                 entities more aware of
                 issues involving the
                 encroachment of population
                 along pipeline
                 rights-of-way.
                 User fee assessment: Within
                 1 year, transmit to the
                 Congress a report analyzing  Closed: A draft report was
                                              approved by the pipeline
 60301(nt)       the present assessment of    safety advisory committees in
 17              pipeline safety user fees    5/97. A final report was
                 solely on the basis of
                 mileage to determine whether prepared and submitted to
                 this or another measure      Congress in 3/98.
                 would be more appropriate.

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)

  Section       Statutory requirement                  Status
                                          Closed: A study of best practices
            One-call notification         to prevent damage to underground
            systems: If information is    facilities, Common Ground: Study
            readily available, undertake  of One-Call Systems and Damage
            a study of damage prevention  Prevention Best Practices, was
 7302(a)    practices associated with     published in 8/99. More than 160
 49 U.S.C.  existing one-call             government employees and
 6105       notification systems and,     underground facility operators
            within 1 year of enactment of contributed to the report.
            this chapter, publish a       Follow-up action to establish a
            report on the practices that  foundation for implementing the
            are most and least            recommendations and best
            successful.                   practices is now being
                                          established.

Source: For columns 1 and 2, GAO's analysis of pipeline safety statutes; for
column 3, status reports from OPS.

GAO Contacts and Staff Acknowledgements

Phyllis F. Scheinberg (202) 512-3650
James Ratzenberger (202) 512-3650

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)

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

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

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
  

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.

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.

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.).

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.

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.

10. The 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.

11. The 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.

12. One 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.

13. The 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.

14. According 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.

15. OPS 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.

16. In 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.

17. The 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).

18. According 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.

19. Pipeline Safety Program, Office of Inspector General, U.S. Department of
Transportation, RT-2000-069 (Mar. 13, 2000).

20. The 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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