ANNUAL REPORT ON PIPELINE SAFETY

CALENDAR YEAR 1993

Prepared By:

U.S. Department of Transportation

Research and Special Programs Administration

Office of Pipeline Safety

Washington, DC 20590

Table of Contents

LIST OF TABLES AND APPENDICES......................................................................................... iii

BACKGROUND............................................................................................................................... 1

PROGRAM HIGHLIGHTS AND DIRECTION.............................................................................. 3

REGULATORY ACTIVITIES.......................................................................................................... 5

FEDERAL/STATE PARTNERSHIP................................................................................................. 10

COMPLIANCE................................................................................................................................. 22

ACCIDENTS AND INVESTIGATIONS.......................................................................................... 24

TRANS-ALASKA PIPELINE SYSTEM.......................................................................................... 32

RESEARCH AND TECHNICAL ACTIVITIES................................................................................ 33

TRAINING AND INFORMATION DISSEMINATION.................................................................. 34

DRUG TESTING INSPECTION AND ENFORCEMENT.............................................................. 37

THE OIL POLLUTION ACT OF 1990............................................................................................. 38

JUDICIAL ACTIONS........................................................................................................................ 40

REPORT UNDER THE MINERAL LEASING ACT........................................................................ 41

ii

Page

Table 1 Membership Rosters: Technical Pipeline Safety Standards Committee and

Technical Hazardous Liquid Pipeline Safety Standards Committee........................... 9

Table 2 Natural Gas Pipeline Safety Grant Allocation............................................................ 11

Table 3 States Participating in the Federal/State Cooperative Gas and

Hazardous Liquid Pipeline Safety Program in 1993................................................... 12

Table 4 1993 Hazardous Liquid Pipeline Safety Grant Allocation......................................... 13

Table 5 1993 State Natural Gas Pipeline Safety Personnel and

1993 State Hazardous Liquid Pipeline Safety Personnel...................................... 14-15

Table 6 1993 Natural Gas State Inspector Qualifications and 1993 Hazardous

Liquid State Inspector Qualifications.................................................................... 17-18

Table 7 1993 State Agency Inspection Activity - Natural Gas and

1993 State Agency Inspection Activities - Hazardous Liquid............................... 19-20

Table 8 1993 Inspection and Compliance Profile................................................................... 23

Table 9 1993 Natural Gas Transmission and Gathering Pipeline

Incidents Reported by Cause..................................................................................... 24

Table 10 1993 Natural Gas Distribution Pipeline Incidents

Reported by Cause................................................................................................... 24

Table 11 Summary of Natural Gas Transmission & Gathering Pipeline

Failures, Fatalities, and Injuries (1989-1993)................................................................ 25

Table 12 Summary of Natural Gas Distribution Pipeline

Failures, Fatalities, and Injuries (1989-1993)................................................................ 25

Table 13 Summary of Hazardous Liquid Pipeline

Failures, Fatalities, and Injuries (1989-1993)................................................................ 26

Table 14 Hazardous Liquid Pipeline Accidents Reported by Cause......................................... 27

Table 15 Summary of Liquid Pipeline Accidents Reported by Commodity............................. 27

Table 16 1993 Economic Impact of Pipeline Accidents........................................................... 28

List of Tables and Appendices

iii

Page
Table 17 1993 Pipeline Safety Training Conducted by TSI...................................................... 35

Table 18 1993 Natural Gas Pipeline Federal Land Data............................................................. 41

Table 19 1993 Hazardous Liquid Pipeline Federal Land Data.................................................... 42

APPENDIX A: 1993 Natural Gas/Hazardous Liquid Enforcement

Cases Opened................................................................................................. 43

APPENDIX B: 1993 Natural Gas/Hazardous Liquid Enforcement

Cases Closed................................................................................................... 47

APPENDIX C: 1993 Natural Gas/Hazardous Liquid Enforcement Cases -

Warning Letters.............................................................................................. 51

APPENDIX D: Office of Pipeline Safety Locations................................................................ 53

Office of Pipeline Safety Regional Boundaries................................................................................... 2

iv

Page
Section 16 of the Natural Gas Pipeline Safety Act

of 1968 (NGPSA), as amended (49 U.S.C. App. §

1671 et seq.), and Section 213 of the Hazardous

Liquid Pipeline Safety Act of 1979 (HLPSA), as

amended (49 U.S.C. App. § 2001 et seq.), require

the Department of Transportation to report

annually on its pipeline safety program. This

report provides an overview of pipeline safety

program activities during Calendar Year (CY)

1993.

The Department’s pipeline mission is to protect

the people and the environment of the United

States through a comprehensive, risk-based

pipeline safety program. The Department

develops, issues, and enforces minimum pipeline

safety regulations. NGPSA provides for Federal

safety regulation of pipeline facilities used in the

transportation of natural gas, while HLPSA

provides for safety regulation of pipeline facilities

used in the transportation of hazardous liquids.

Both NGPSA and HLPSA provide a framework

for promoting pipeline safety through exclusive

Federal authority for regulation of interstate

pipeline facilities, and Federal delegation to the

states of all or part of the regulatory responsibility

for intrastate pipeline facilities.

The Department provides grant funding to support

states in conducting intrastate gas and hazardous

liquid pipeline safety programs; ensures operator

compliance through a risk-based pipeline inspection

plan and use of enforcement actions as a deterrent

against violators; collects, compiles, and analyzes

pipeline safety and operating data; and conducts

training through its Transportation Safety

Institute (TSI), for government and industry

personnel in application of the pipeline safety

regulations. The Department also undertakes

research with emphasis on solid analytical

methodologies and state-of-the-art technology to

provide the foundation necessary for planning,

evaluating, and implementing the pipeline safety

program.

The Department’s regulatory authority covers

approximately 1.7 million miles of natural gas

pipelines managed by almost 900 transmission

and gathering operators, more than 1,400

distribution operators, 106 liquefied natural gas

(LNG) operators, about 52,000 master meter

operators, as well as 165,845 miles of hazardous

liquid pipelines managed by 213 operators and

2,200 miles of carbon dioxide pipelines.

Section 7005 of the Consolidated Omnibus

Budget Reconciliation Act of 1985 (Pub. L. 99-

272, 49 U.S.C. App. § 1682a) authorizes the

Secretary of Transportation to assess and collect

annual fees from the pipeline industry to fund the

cost of the Department’s pipeline safety program

under NGPSA and HLPSA.

Title IV of the Oil Pollution Act of 1990 (OPA 90),

Pub. L. 101-380, 104 Stat. 484, requires national

planning and response system for oil spills. The

Office of Pipeline Safety (OPS) is responsible for

implementing OPA 90 requirements as they apply

to onshore oil pipelines that could reasonably be

expected to cause significant and substantial harm

to the environment by discharging oil into or on the

navigable waters of the United States and

adjoining shorelines.

The Department’s pipeline safety mandate is

administered, under delegation from the Secretary,

by the Research and Special Programs

Administration (RSPA) through the OPS. The

functions of the Department’s Agency Authorized

Officer (AAO) for the Alaska Natural Gas

Transportation System project are also assigned to

OPS. Under the organizational structure

established by Executive Order 12142 (“The

Alaska Natural Gas Transportation System”), the

AAO represents the Department within the Office

of the Federal Inspector, and is responsible for

monitoring and expediting all project-related

activities that fall within the purview of the

Department.

BACKGROUND

1
At the end of 1993, OPS had approximately 65

employees. Half of these employees work at

Headquarters in Washington, DC, and the other

half are located in five Regional Offices across the

country (Eastern Region--Washington, DC;

Southern Region--Atlanta, GA; Central Region--

Kansas City, MO; Southwest Region--Houston,

TX; Western Region--Lakewood, CO) and at

RSPA’s training facility, TSI, in Oklahoma City,

OK (see regional boundary map below).

2

Eastern

Region

Southern

Region

OPS_REGIONS

DT 7/96

Office of Pipeline Safety

 Regional Boundaries

Southwest

Region

Houston

Atlanta

Washington, D.C.

Central

Region

Kansas City

Western

Region

Lakewood

iv
In 1993, the Work Redesign of OPS continued to

be implemented. In addition, work continued in

establishing a methodology for risk assessment.

OPS published an interim final rule for onshore

oil spill response plans to be submitted by operators under the OPA 90. And finally, OPS began

work to implement the mandates in the Pipeline

Safety Act of 1992 (PSA 92).

Work Redesign. The Work Redesign effort to

restructure and establish new work procedures and

tasks continued to be implemented. The decentralization of OPS continued with additional responsibility placed with the Regions following the

successful delegation of many responsibilities last

year. Additional authority for review, processing,

and signature of enforcement cases and state program monitoring documents was delegated to the

Regional Directors. Some of the improved and

more efficient areas of Regional responsibilities

that were introduced last year that have been improved include accident investigations, safety inspections, inter-regional inspections, and office

procedures.

At OPS Headquarters, employees began to use the

manual for human resource development. The

manual provides policy and procedures for awards,

training, orientation of new staff, job announcements, and individual development programs.

The incorporation of new information system software was accelerated during 1993. Last year’s

successful introduction of Lotus Notes led to more

efficient and productive work in OPS. The interactive features of Lotus Notes have proven to be a

boon to the review and approval of documents. All

of the Regions were successfully tied together into

the OPS Local Area Network thereby electronically tying the geographically dispersed Regions

and Headquarters. This has provided OPS the capability of sharing and reviewing documents by

everyone in the organization.

Noteworthy in the new work paradigm are the

heightened efforts at increasing coordination with

other Federal agencies, the states and the pipeline

industry in future programmatic initiatives. Such

agencies as the U.S. Coast Guard, Minerals Management Service of the Department of the Interior,

Federal Energy Regulatory Commission, National

Oceanic and Atmospheric Administration, Environmental Protection Administration, and many

other agencies joined RSPA in discussions regarding regulations and the Risk Assessment

Prioritization (RAP) process. The National Association of Pipeline Safety Representatives

(NAPSR) was instrumental in helping RSPA develop the RAP process and in discussions regarding the many legislative mandates in PSA 92.

Risk Assessment. To provide a basis for allocating government resources to areas that have the

greatest potential to improve pipeline safety, OPS

began last year to develop a RAP process. This

year, work continued on this important effort by

getting input from pipeline operators, the public,

and other government and state agencies. The RAP

process was improved from information and recommendations obtained from all of these sources.

In addition, discussions were begun to possibly

develop risk methodology into the OPS regulatory

program by establishing a structure to evaluate

pipeline risks and their consequences, to develop

solutions to address the risks, and to establish priorities for implementing the solutions. These discussions were held with pipeline operators that

have risk management programs, risk management

experts, and pipeline industry associations.

Environmental Action Plan. The PSA 92 gave

the Department responsibility to protect the environment from pipeline spills. As a result of PSA

92, RSPA embarked on an Environmental Action

Plan that included the prioritization of mandated

regulatory requirements, such as: (1) hydrostatic

testing of hazardous liquid pipelines that have not

been previously tested; (2) requiring periodic inPROGRAM HIGHLIGHTS AND DIRECTION

3
spection of pipelines in environmentally sensitive

and high-density population areas using instrumented internal inspection devices; (3) not excepting a hazardous liquid pipeline from regulation

solely because it operates at low internal stress;

and (4) requiring liquid operators to have a damage prevention program. Another feature of the

Environmental Action Plan was analyzing various

Geographic Information System (GIS) mapping alternatives and determining a strategy for creating

reasonably accurate maps of pipelines. In addition, an important element was the redirection of

the pipeline state and compliance program to: (1)

increase state grants and state participation in the

program; (2) focus on inspecting hazardous liquid

pipelines and pipeline construction; (3) assign state

liaison personnel to the Regions; and (4) increase

inspector training. Finally, the Spill Response

Planning program under OPA was initiated, as discussed below.

Hazardous Liquid Pipelines. In light of the environmental provisions and legislation targeting

hazardous liquid pipelines in PSA 92, inspections

of hazardous liquid pipelines were increased in

1993. In addition, work was begun to develop regulations and studies as required by PSA 92. Some

of the mandates in the PSA 92 that focused on hazardous liquid pipelines are: establishing standards

for the use of instrumented internal inspection devices; establishing standards for emergency flow

restricting devices and the associated leak detection systems; identifying environmentally sensitive areas; establishing employee qualification; and

not excepting low stress pipelines from the regulations.

Natural Gas Pipelines. The PSA 92 also mandates a number of initiatives to safeguard natural

gas pipelines. Some of the most significant mandates include: prescribing circumstances for the installation of excess flow valves; advising customers of the proper maintenance of these excess flow

valves; surveying customers regarding their views

on who should maintain excess flow valves; and

surveying operators to determine the extent to

which they have plans for the safe management

and replacement of cast iron pipelines. Work was

initiated on most of these legislative requirements.

Spill Response Planning. Under OPA, the Department of Transportation is responsible for establishing procedures, methods and requirements

for equipment to prevent and contain discharge of

oil from vessels and transportation related facilities. The RSPA has responsibility to establish

procedures and planning requirements to prevent

discharges from and to contain oil and hazardous

substances in pipelines. On January 5, 1993, OPS

published its interim final rule for Response Plans

for Onshore Oil Pipelines as 49 CFR Part 194 (58

FR 244). The rule addressed several critical areas

of planning, including: economically and environmentally sensitive areas, response actions and strategies, integration of incident command structures,

pre-approval of removal actions, training requirements, and drill and exercise requirements. More

than 1,000 spill response plans were received by

the required date of July 18, 1993. Review of

these plans was begun immediately to meet the plan

approval date of early 1995.

4
OPS develops regulations to assure safety in

design, construction, testing, operation, and

maintenance of pipeline facilities and in the siting,

construction, operation, and maintenance of

pipeline facilities. Regulations are also issued to

administer the LNG safety program and delineate

requirements for onshore response plans. These

regulations are published in 49 CFR: Part 190,

Enforcement Procedures; Part 191, Natural Gas

Reporting Requirements; Part 192, Natural Gas

Pipelines; Part 193, Liquefied Natural Gas

Facilities; Part 194, Response Plans for Onshore

Oil Pipelines; Part 195, Hazardous Liquid

Pipelines; Part 198, State Grants; and Part 199,

Drug and Alcohol Testing.

To provide expert input during development of

pipeline safety regulations, NGPSA and HLPSA

established two pipeline safety advisory

committees, the Technical Pipeline Safety

Standards Committee and the Technical Hazardous

Liquid Pipeline Safety Standards Committees.

The Committees review proposed regulations for

technical feasibility, reasonableness, and

practicability. The Committees also provide

advice to the Department on pipeline safety and

environmental issues. Each Committee is

comprised of 15 members: six from the public,

five from government, and four from the pipeline

industry. Committee members are widely

respected pipeline safety or technical experts.

Committee members as of December 31, 1993, are

listed in Table 1 on page 9.

Proposed Rulemakings. In its continuing effort

to improve and update existing regulations, RSPA

issued the following Notices of Proposed

Rulemaking (NPRMs) in 1993:

Transportation of a Hazardous Liquid in

Pipelines Operating at 20 Percent or Less of

Specified Minimum Yield Strength. [Docket

PS-117, Notice 3; 58 FR 12213; March 3, 1993.]

The Federal pipeline safety standards governing

hazardous liquid pipelines do not apply to

pipelines operated at a stress level of 20 percent or

less of the specified minimum yield strength

(SMYS) of the pipe. This notice proposed to

revise the current exception and to apply the

pipeline safety standards to certain pipelines

operating at a stress level of 20 percent or less of

SMYS. RSPA expects that this rulemaking will

improve public safety and environmental protection

by minimizing the possibility of accidents.

Excess Flow Valve Installation on Service

Lines. [Docket PS-118; Notice 2; 58 FR 21524;

April 24, 1993.] Excavators frequently sever or

damage gas service lines, causing loss of life,

injury, or property damage by fire and explosion.

RSPA proposed to require the installation of

excess flow valves (EFVs) on certain new and

replaced gas service lines to improve safety and

mitigate the consequences of service line

incidents. EFVs shut off the flow of gas by

automatically closing when a line is broken.

Final Rules. In its continuing effort to enhance

pipeline safety, RSPA issued the following Final

Rules in 1993:

Response Plans for Onshore Oil Pipelines.

[Docket No. PS-130; FR 58 244; January 5,

1993.] This interim final rule established

regulations requiring response plans for certain

pipelines that transport oil. These regulations

were mandated by the Federal Water Pollution

Act, as amended by the OPA 90. The purpose of

these requirements was to improve response

capabilities and minimize the environmental

impact of oil discharges from pipelines. Although

RSPA issued an interim final rule, comments were

invited and changes were made where appropriate

to the rule.

Update of Standards Incorporated by Reference.

[Docket PS-131; Amdt. 192-68, 193-8 & 195-48;

58 FR 14519; March 18, 1993.] This final rule

updated existing references to voluntary

specifications and standards to reflect more recent

REGULATORY ACTIVITIES

5
editions of each document. Many currently

referenced editions are outdated and some are outof-print. This final rule enabled pipeline operators

to utilize current technology, materials, and

practices, thereby reducing costs and enhancing

economic growth consistent with the President’s

goal of regulatory review.

Gas Detection and Monitoring in Compressor

Station Buildings. [Docket PS-100; Amdt. 192-

69; 58 FR 48460; September 16, 1993.] This

final rule required that each compressor building

in a gas pipeline compressor station have a fixed

gas detection and alarm system by September 16,

1996, unless the building has at least 50 percent of

its upright side area permanently open or is in an

unattended field compressor station of 1,000

horsepower or less. The history of reported

incidents at compressor stations shows a potential

for leaking gas to accumulate, undetected, inside

compressor buildings. The purpose of the gas

detection and alarm systems is to detect mixtures

of gas in air and warn persons before it becomes

flammable.

Leakage Surveys on Distribution Lines Located

Outside Business Districts. [Docket PS-123;

Amdt. 192-70; 58 FR 54524; October 22, 1993.]

This rule required operators of distribution lines

located outside business districts to use leak

detectors in required leakage surveys. This

provides greater assurance that operators identify

all hazardous leaks during required leak surveys.

Also, the final rule assures that leakage survey data

no more than three years old is used to evaluate

lines for corrosion.

Requests for Information. RSPA often solicits

public comment in an attempt to gain information

on issues surrounding upcoming regulatory

initiatives. RSPA issued the following request for

information in 1993:

Office of Pipeline Safety: Risk Assessment

Prioritization. [Docket PS-132; FR 58 51402;

October 1, 1993.] RSPA implemented a RAP

process to rank actions that could be taken by OPS

according to their potential for reducing the risk of

pipeline failures. The ranked list became the base

upon which OPS management will decide how to

commit limited resources to specific tasks. RSPA

invited representatives of industry, government

agencies, environmental organizations, and other

members of the public to contribute information

on causes of pipeline failures. The information

was used in the RAP process.

Regulatory Review: Gas Pipeline Safety

Standards; NAPSR Report on

Recommendations for Revision of Gas Pipeline

Safety Standards. [Docket PS-124; Notice 2; 58

FR 59431; November 9, 1993.] This document

invited public comment on rulemaking proposals

from NAPSR for the safety of natural and other gas

pipelines. NAPSR is a non-profit organization of

state gas pipeline safety directors, managers,

inspectors, and technical personnel who serve to

support, encourage, develop and enhance pipeline

safety regulation.

The proposals resulted from a study NAPSR

conducted, at the request of RSPA, of pipeline

safety regulations which they considered unclear

or difficult to enforce. Comments on the NAPSR

study assisted RSPA in developing a position on

the NAPSR recommendations.

Federal Waivers Under the Act. In circumstances

where absolute compliance with a pipeline safety

regulation would not be appropriate and where

sufficient alternative safeguards to the public

safety are implemented, RSPA, at its discretion,

may grant an operator’s petition for a waiver from

the regulations applicable to interstate pipeline

transportation. The following waivers have been

granted:

March 15, 1993: P-90-1W [Notice 2]

Transportation of Natural and Other Gas by

Pipeline; Grant of Waiver. RSPA granted a waiver

to Panhandle Eastern Corporation from compliance

with the repair requirements of 49 CFR

192.713(a). Panhandle will install a proprietary

composite reinforced (CR) sleeve material (Clock

SpringTM manufactured by Clock Spring Company

of North America [Clock Spring Company], Long

Beach, CA) as a full encirclement wrapped sleeve

for the repair of imperfections and damages in

6
steel pipe at six locations on its Line #2 in Fayette

County, Ohio. Currently, under § 192.713(a),

each imperfection or damage that impairs the

serviceability of a segment of steel transmission

line operating at or above 40 percent of specified

minimum yield strength (SMYS) must be repaired

by either cutting out the segment and replacing a

cylindrical piece of pipe or by installing over the

segment a full encirclement welded split sleeve.

December 14, 1993: P-92-2W [Notice 2]

Transportation of Hazardous Liquids by Pipeline;

Petition for Waiver. ARCO Oil and Gas Company

petitioned RSPA for a waiver from compliance

with 49 CFR 195.412(a), inspection of right-ofway and crossing under navigable waters. Section

194.412(a) requires inspection of surface conditions

on or adjacent to each pipeline right-of-way at

intervals not exceeding 3 weeks, but at least 26

times each calendar year. The petition applied to

the Sheep Mountain Unit gathering system, a 6.9

mile carbon dioxide pipeline system in Colorado.

State Waivers: A state agency certified under

NGPSA or HLPSA may waive compliance with a

safety regulation applicable to intrastate pipeline

transportation, if, after receiving notice, RSPA

concurs in the action. RSPA approved the following petitions for state waivers in 1993:

February 11, 1993: RSPA approved a waiver

granted by the New Hampshire Public Utilities

Commission to Northern Utilities, Inc. The waiver

of 49 CFR Part 193 permitted the use of a mobile

LNG facility in Rochester, New Hampshire, for

the purposes of preventing extreme pressure drops

in a certain portion of the area’s distribution system during “peak” usage times.

March 24, 1993: RSPA approved a waiver granted

by the Arizona Corporation Commission to Southwest Gas Corporation. The waiver authorized the

use of plastic mechanical fittings that are not covered by specifications listed in 49 CFR Part 192.

March 25, 1993: RSPA approved a waiver granted

by the Michigan Public Service Commission to

Consumers Powers Company. The waiver permitted the aboveground installation of a 4-inch

plastic gas main in a 6-inch steel casing pipe across

a bridge in Macomb County. OPS did not object

because the waiver was not inconsistent with pipeline safety.

April 1, 1993: RSPA approved a waiver granted

by the Washington Utilities and Transportation

Commission to Washington Natural Gas Company,

which waived the definition of “main” in 49 CFR

192.3. The waiver permitted no more than two

adjoining residential-building customers to be supplied gas from a common pipeline without classifying that pipeline as a “main.”

June 28, 1993: RSPA approved a waiver granted

by the Georgia Public Service Commission to

Anheuser Busch. The waiver of 49 CFR Part 192

permitted the use of a plastic gas pipeline under

the I-75 highway. Based on the material, test, and

construction data regarding the pipeline, it was

determined that the pipeline can be used to safely

transport gas, as long as it is operated and maintained under Part 192 standards.

July 30, 1993: RSPA approved a waiver granted

by the Railroad Commission of Texas to Amerada

Hess Corporation. The waiver of compliance with

the plastic pipeline standards in 49 CFR 192.59,

192.147, 192.191, 192.281(a) and (d) (1), and

192.63 (a) (2) applies to two segments of a fiberglass gathering system, totaling 0.37 miles of pipeline, that is located in Seminole, Texas.

August 16, 1993: RSPA approved a waiver granted

by the Missouri Public Service Commission from

compliance with 49 CFR 192.321(a), plastic pipe

in gas lines be installed above ground. The need

for a waiver was caused by flooding and damage

7
to the gas line serving the cities of Hermann,

Berger and New Haven, Missouri. The City installed approximately 2,000 feet of 2-inch polyethylene plastic pipe above ground level to provide temporary emergency service to the cities.

September 16, 1993: RSPA approved a waiver

granted by the Connecticut Department of Public

Utility Control to Connecticut Natural Gas Corporation, Southern Connecticut Gas Company, and

Yankee Gas Service Company. Alternate safety

requirements to Part 193 requirements were approved for mobile LNG facilities, because the alternate safety requirements would not be a danger

to public safety.

December 3, 1993: RSPA approved a waiver

granted by the Rhode Island Public Utilities Commission to Providence Gas Company. Alternate

safety requirements to Part 193 requirements were

approved for mobile LNG facilities because the

alternate safety requirements would not be a danger to public safety.

Advisory Bulletins: RSPA uses Advisory

Bulletins to inform affected pipeline operators and

all Federal and state pipeline safety personnel of

matters that have the potential of becoming safety

and/or environmental risks. During 1993, RSPA

issued the following Advisory Bulletins:

January 1, 1993: Advisory Bulletin ADB-93-01

informed Propane System Owners and Operators

of the need to inform the public of possible hazards

relating to snow accumulation on pipeline

facilities, and to monitor the potential impact of

snow accumulation of those facilities.

April 5, 1993: Advisory Bulletin ADB-93-02

directed gas pipeline facility owners and operators

to review and assess their § 192.615(d)

continuing educational programs as applied to

customers and the public.

July 29, 1993: Advisory Bulletin ADB-93-03

advised pipeline operators in flood areas of

measures they should consider to assure the safety

of those pipelines. In particular, pipeline operators

should review emergency plans to assure that they

adequately cover conditions possible in the current

severe flooding.

November 16, 1993: Advisory Bulletin ADB-93-

04 requested that persons seeking interpretations

of pipeline safety regulations include certain

information.

8
9

Bruce B. Ellsworth (G)

Commissioner

New Hampshire Public Utilities

 Commission

8 Old Suncook Road

Concord, NH 03301

William R. Harper (I)

Consultant

4334 Wood Trace

Owensboro, KY 42303

Jack M. Hilliard (I)

Manager

City of Florence Gas Department

PO Box 2818

Florence, AL 35631

Vincent R. Holley (P)

132 Cherokee Road

Hendersonville, TN 37075

Melvin A. Judah (P)

Consulting Engineer

560 N Street, SW., Apt . N-204

Washington, DC 20024

Ruth K. Kretschmer (G)

Commissioner

Illinois Commerce Commission

State of Illinois Center

100 West Randolph Street

Chicago, IL 60601

Darrell A. McKown (G)

Manager, Gas Pipeline Safety Section

West Virginia Public Service

Commission

PO Box 812

Charleston, WV 25323

Table 1

Membership Roster: Technical Pipeline Safety Standards Committee

Membership: (G) = Government; (I) = Industry; (P) = Public

(NOTE: As of 12/31/93, there were five vacancies)

Richard J. Morgan (I)

Assistant Vice President

Steam Operations

Consolidated Edison Co. of New York, Inc.

708 First Avenue, 8th Floor

New York, NY 10017

Jack M. Webb (P)

Attorney at Law

5847 San Felipe

Suite 2300

Houston, TX 77057

Chris M. Zerby (G)

Environmental Engineer

Office of Pipeline and Producer Regulation

Federal Energy Regulatory Commission

825 North Capitol Street, NE., Room 7312-K

Washington, DC 20426

Carl D. Clay (I)

Director, Transportation

 and Logistics

Marathon Oil Company

539 South Main Street

Findlay, OH 45840

Joan A. Jennings (G)

Deputy Chief, Special Services and

Pipeline Safety Division

California State Fire Marshal

7171 Bowling Drive, Suite 600

Sacramento, CA 95823

Wayne D. Perry (P)

Professor of Public Policy and

 Operations Research

The Institute of Public Policy

George Mason University

Pohick Module, Room 23

Fairfax, VA 22030-4444

Milton D. Randall (P)

Consulting Welding Engineer

12727 Campsite Trail

Cypress, TX 77429

Gerald D. Rhodes (G)

Senior Petroleum Engineer

Minerals Management Service

Department of the Interior

381 Elden Street

Herndon, VA 22070

Gary D. Robinson (P)

Vice President,

Energy Development

Ecology and Environment, Inc.

368 Pleasantview Drive

Lancaster, NY 14086

Gary A. Smith (G)

Chief, Safety

Arizona Corporation

 Commission

1200 West Washington Street

Phoenix, AZ 85007

Merril H. Werts (P)

Bank Consultant/

 Board Chairman

Stockgrowers State Bank

1228 Miller Drive

Junction City, KS 66441

Membership Roster: Technical Hazardous Liquid Pipeline Safety Standards Committee

Membership: (G) = Government; (I) = Industry; (P) = Public

(NOTE: As of 12/31/93, there were seven vacancies)
The Federal/state partnership is the cornerstone for

assuring uniform implementation of the pipeline

safety program nationwide. While the Federal

Government is primarily responsible for

developing, issuing, and enforcing minimum

pipeline safety standards, Congress intended for

states to take full and active safety jurisdiction

over all intrastate pipelines. States clearly are at

the front lines in delivering the pipeline safety

program, being closer to the pipeline operators and

the consumers of pipeline products than the

Federal Government. Alone, neither the Federal

Government nor the states can assure the proper

level of pipeline safety in the country today.

Together, Federal and state resources can be

leveraged to deliver a cost-effective program that

has one of the best safety records in transportation.

Refer to Table 3 on page 12 for a list of states

participating in the Federal/state partnership

program.

Natural Gas Pipeline Safety Program. NGPSA

provides for a state agency to assume all aspects of

the pipeline safety program for intrastate facilities

under its jurisdiction if the state agency certifies

annually that it complies with certain provisions.

A state agency must adopt and enforce Federal

safety standards established under the NGPSA.

The state must inspect pipeline operations on a

periodic basis to ensure compliance with the

regulations. The state must also have authority to

require pipeline operators to maintain records,

make reports, and file plans for inspection and

maintenance. Additionally, the state must have

injunctive and monetary sanctions substantially

the same as provided under the NGPSA.

The NGPSA also permits a state agency that does

not qualify for certification to undertake certain

safety activities under an agreement with the

Department, principally conducting periodic

inspection of pipeline operators. The state must

also establish procedures for approval of operator

plans for inspection and maintenance and must

maintain records and reports to assure pipeline

operator compliance with Federal safety standards.

In the event of a probable violation of the

standards, the state must notify the Department,

which initiates any enforcement action. If a state

agency does not submit a certification or seek an

agreement, all intrastate facilities within the state,

and any category of intrastate facility not covered

by a state certification or agreement, remain under

the Department’s safety jurisdiction.

Under the NGPSA, the Department may also

allow a state to act as its agent and inspect

interstate pipelines traversing the state. To qualify

as an agent, a state must demonstrate it is

satisfactorily performing all responsibilities

assigned under its certification for oversight of

intrastate pipelines. Beginning January 1, 1995,

the Department will require existing agents to have

safety jurisdiction over all intrastate pipelines to

remain interstate agents. As an agent, a state must

notify the Department of any probable violation

discovered, and the Department retains

responsibility for taking appropriate enforcement

action.

States have overwhelmingly supported the

concept of common stewardship in gas pipeline

safety. In 1993, 46 state agencies, the District of

Columbia, and Puerto Rico held certifications, and

3 state agencies operated all or parts of their

programs under agreements. Additionally, 11

state agencies acted as agents on behalf of the

Department for inspecting interstate gas pipelines

(see Table 3 on page 12). Three states did not

participate in the program: Alaska, Idaho and

South Dakota.

Each state agency participating in the pipeline

safety program is eligible for grant funding of up to

50 percent of personnel, equipment, and activity

costs associated with carrying out its program.

The amount of funding available in any given year

depends upon the congressional appropriations

process. Since 1981, appropriations have not been

adequate to cover state requests for grant funds,

and the Department developed a formula to

FEDERAL/STATE PARTNERSHIP

10
allocate available funds to support state programs.

Performance factors used for allocating funds in

1993 included: amount of state request; extent of

state jurisdiction over intrastate operators; number

and qualification of inspectors; number of

inspection person-days; and existence of an

underground utility damage prevention law.

In 1993, Congress appropriated $7,000,000 for

pipeline safety grant funding. The Department

allocated a total of $6,300,000 to state agencies

participating in the gas program. Ninety percent of

the appropriation was assigned to activities

conducted under the NGPSA and

10 percent to activities

conducted under the

HLPSA (see Table 2).

Funding in 1993

covered an average of

34 percent of overall

state requests for grant

funds to defray gas

program costs.

Hazardous Liquid

Pipeline Safety

Program. The HLPSA

provides for state

participation in

regulating the safety of

pipelines transporting

hazardous liquids under

a certification or an

agreementsubstantially

the same as the NGPSA.

At present, fewer states

participate in the

hazardous liquid

program than in the gas

program, reflecting the

fact that the number of

miles of liquid lines is

significantly lower than

the number of miles of

gas lines. With

enactment of the PSA

92 lifting the exception

to regulating low-stress pipelines, the Department

expects additional states to begin participating in

the liquid program.

In 1993, a total of 10 state agencies participated in

the hazardous liquid program -- nine state agencies

held certifications and one state operated under an

agreement. Furthermore, three of these states also

acted as agents on behalf of the Department for

inspecting interstate hazardous liquid lines (see

Table 3 on page 12). In 1993, the Department

allocated a total of $700,000 to state agencies

Table 2

Natural Gas Pipeline Safety Grant Allocation

State $ Allocation State $ Allocation

 Alabama 209,570 Nebraska 75,042

 Arizona 227,804 Nevada 82,889

 Arkansas 162,504 New Hampshire 47,241

 California 232,989 New Jersey 171,799

 Colorado 104,411 New Mexico 134,432

 Connecticut 131,791 New York 314,665

 Delaware 15,860 North Carolina 150,508

 District of Columbia 41,892 North Dakota 32,659

 Florida 36,406 Ohio 202,991

 Georgia 172,170 Oklahoma 156,993

 Illinois 187,464 Oregon 107,970

 Indiana 135,523 Pennsylvania 184,199

 Iowa 116,698 Puerto Rico 11,014

 Kansas 199,164 Rhode Island 58,893

 Kentucky 178,065 South Carolina 80,072

 Louisiana 206,180 Tennessee 193,651

 Maine 10,402 Texas 283,173

 Maryland 99,417 Utah 93,033

 Massachusetts 184,366 Vermont 48,709

 Michigan 181,174 Virginia 126,298

 Minnesota 222,727 West Virginia 116,333

 Mississippi 103,438 Wisconsin 108,108

 Missouri 181,072 Wyoming 89,749

 Montana 25,492

Subtotal $6,237,000

State Travel Expenses $63,000

Total $6,300,000

11
12

Table 3

States Participating in the Federal/State Cooperative Gas

and Hazardous Liquid Pipeline Safety Program in 1993

NATURAL GAS PROGRAM

STATE AGENCIES UNDER 5(a) CERTIFICATION (48)

Alabama Iowa Nebraska Puerto Rico

Arizona Kansas Nevada Rhode Island

Arkansas Kentucky New Hampshire South Carolina

California Louisiana New Jersey Tennessee

Colorado Maine New Mexico Texas

Connecticut Maryland New York Utah

District of Columbia Massachusetts North Carolina Vermont

Florida (Public Service Commission) Michigan North Dakota Virginia

Florida (State Treasurer - LP Gas Division) Minnesota Ohio Washington

Georgia Mississippi Oklahoma West Virginia

Illinois Missouri Oregon Wisconsin

Indiana Montana Pennsylvania Wyoming

STATE AGENCIES UNDER 5(b) AGREEMENT (3)

Delaware Kentucky (Municipals) Wyoming (Intrastate Transmission Lines)

STATE AGENCIES ACTING AS INTERSTATE AGENTS (11)

Arizona Michigan Ohio West Virginia

Connecticut Minnesota Rhode Island Rhode Island

Iowa Nevada Utah

HAZARDOUS LIQUID PROGRAM

STATE AGENCIES UNDER 205(a) CERTIFICATION (9)

Alabama Louisiana Oklahoma

Arizona Minnesota Texas

California (Fire Marshal) New York West Virginia

STATE AGENCY UNDER 205(b) AGREEMENT (1)

Mississippi

STATE AGENCIES ACTING AS INTERSTATE AGENTS (3)

Arizona California (Fire Marshal) Minnesota
Table 4

1993 Hazardous Liquid Pipeline Safety Grant Allocation

State $ Allocation State $ Allocation

 Alabama 18,739 Mississippi 2,775

 Arizona 37,300 New York 22,389

 California (FM) 272,599 Oklahoma 66,947

 Louisiana 49,091 Texas 125,336

 Minnesota 84,558 West Virginia 13,266

Subtotal $693,000

State Travel Expenses $7,000

Total $700,000

participating in the liquid program, covering an

average of 30 percent of state costs. This level

represented an increase over 1992 funding which

covered an average of 22 percent of state costs (see

Table 4 above).

State Pipeline Safety Personnel. One of the

major state uses of Federal grant funds is for

defraying personnel costs. As of December 31,

1993, the states reported a nationwide complement

of 259 safety inspectors (working 218 person

years) in the gas program and 70 inspectors

(working 15 person years) in the liquid program

(see Table 5 on pages 14-15).

Twenty percent of the gas inspectors have

engineering degrees from accredited engineering

schools or are registered professional engineers,

and have a minimum of three years experience as

state or Federal pipeline inspectors monitoring gas

or liquid operators for compliance with state and

Federal pipeline safety regulations. In addition,

they have completed all the applicable TSI training

(or received an exemption) (see Table 6 on pages

17-18).

Improving State Program Performance. The

Department is committed to moving toward full 50

percent funding of eligible state program costs on

a phased basis, tied to improved state performance.

Initially, in distributing funds, the Department

placed emphasis on assisting states to establish

their pipeline safety programs. The Department

has shifted attention to assisting states to enhance

program performance. A state’s performance

would be based on the results of RSPA’s annual

field evaluation (assessing operating practices;

quality of state inspections; investigations and

enforcement actions; and adequacy of record

keeping) and selected information provided in the

state’s annual certification/agreement (extent of

safety jurisdiction; inspector qualifications; number

of inspection person-days; and adoption of

applicable regulations).

Two critical performance factors are state

13
14

Table 5

1993 Sta te Na tura l Ga s Pipe line Sa fe ty Pe rsonne l 

State Superv is ory Tec hnic al Clerical

Number Pers on Y rs . Number Pers on Y rs . Number Pers on Y rs .

AL PSC 1 0.97 9 7.58 1 0.97

AR PSC 1 1.00 4 4.00 1 0.675

AZ CC 3 1.51 11 9.42 2 1.50

CA PU C 6 1.08 14 9.25 3 2.10

CO PUC 1 0.50 3 3.00 2 0.80

CT DPUC 2 0.45 3 1.25 1 0.20

DC PSC 1 0.12 2 1.30 1 0.10

DE PSC 1 0.10 1 0.40 2 0.05

F L PSC 1 0.50 6 3.68 1 0.50

F L LPG 3 0.10 4 1.36 5 0.26

GA PSC 2 1.70 6 4.63 1 1.00

IA DC 1 0.40 5 2.98 0 0.00

IL CC 2 1.15 7 6.83 1 1.00

IN PSC 1 1.00 4 3.83 0 0.00

KS CC 1 1.00 9 8.58 1 1.00

KY PSC 2 1.75 4 3.25 1 0.75

LA DN R 3 1.86 13 8.46 3 1.25

MA DPU 1 1.00 5 4.75 2 2.00

MD PSC 2 0.70 4 3.06 1 1.00

MI PSC 2 1.11 4 3.46 1 0.54

MN OPS 2 1.25 8 5.34 3 1.88

MO PSC 2 1.14 9 6.75 1 0.54

MS PSC 1 0.99 3 2.99 1 0.99

MT PSC 1 0.13 2 0.54 1 0.106

NC UC 1 1.00 3 2.58 1 1.00

ND PSC 1 0.21 2 0.73 2 0.09

NE SFM 1 0.50 2 2.00 1 0.50

NH PUC 1 0.60 2 1.25 1 1.00

NJ BR C 4 1.60 4 3.50 1 1.00

NM SCC 2 1.33 3 3.00 1 0.09

NV PSC 2 0.125 3 2.04 2 0.10

NY PSC 6 5.65 21 33.58 4 3.50

OH PUC 3 1.30 7 6.42 4 1.00

OK CC 1 0.67 4 4.00 1 0.67

OR PUC 2 0.18 3 2.35 1 0.35

PA PU C 1 0.50 6 5.50 1 0.92
assumption of safety jurisdiction over all

intrastate pipelines and adoption of minimum

one-call notification system requirements. Some

state agencies have had difficulty in obtaining the

necessary legislative authority to comply with

these requirements. In several instances, RSPA

staff has met with key state officials to increase

awareness of the pipeline safety program and

encourage assumption of additional jurisdiction

and/or adoption of one-call requirements.

As a result of increasing emphasis, a number of

states have taken steps to expand their jurisdiction

over intrastate pipelines, including municipal,

master meter, and LPG systems. By the end of

1993, states reported they had jurisdiction over a

total of 11,574 gas operators with 13,179 pipeline

inspection units and 288 liquid operators with 438

15

Ta b le 5 (co ntinue d)

State Super vis ory Tec hnic al Cleric al

Number Pers on Y rs . Number Pers on Y rs . Number Pers on Y rs .

SC PSC 2 0.80 3 2.80 1 0.80

TN PSC 1 0.90 5 4.10 1 1.00

TX R C 10 4.76 31 22.16 13 11.05

UT D BR 2 1.10 2 2.00 1 0.50

VA SCC 2 0.406 4 2.95 3 0.15

VT DPS 1 0.20 1 0.80 0 0.00

W A UTC 1 0.20 1 1.00 1 0.30

W I PSC 3 0.70 3 1.59 3 0.10

W V PSC 2 0.70 6 5.19 1 0.80

W Y PSC 1 0.38 3 1.71 6 0.60

Total 93 45.32 259 217.94 86 44.73

1993 Sta te Ha za rdou s L iquid Pip e line Sa fe ty Pe rson ne l

State Superv isory Tec hnical Cleric al

Number Pers on Y rs . Number Pers on Y rs . Number Pers on Y rs .

AL PSC 1 0.03 7 0.19 1 0.03

AZ CC 1 0.01 5 0.90 0 0.00

CA SFM 3 2.00 7 5.58 4 3.00

LA DNR 2 0.37 2 1.85 2 0.90

MN OPS 2 0.42 4 1.45 3 0.63

MS PSC 1 0.10 1 0.001 1 0.10

NY PSC 1 0.05 9 0.46 2 0.02

OK CC 1 0.34 2 1.17 1 0.34

TX RC 10 0.84 31 3.91 13 1.95

W V PSC 2 0.15 2 0.21 1 0.20

TOTAL 24 4.31 70 15.72 28 7.17
16

pipeline inspection units (see Table 7 on pages 19-

20).

A number of states strengthened their damage

prevention programs during 1993 to comply with

minimum Federal requirements for one-call

notification systems. Outside force damage is the

leading cause of pipeline safety accidents--

accounting for 53 percent of gas distribution, 40

percent of gas transmission and gathering, and 18

percent of hazardous liquid incidents reported to

RSPA in 1993. One-call systems serve as critical

switching centers for excavators to notify pipeline

and other underground facility operators of their

intent to use equipment for digging, tunneling,

demolition, or similar work. Congress explicitly

prescribed the minimum requirements for

establishing and operating one-call notification

systems in the Pipeline Safety Reauthorization Act

of 1988, including:

♦ complete coverage of areas in state

having pipeline facilities;

♦ compliance with operating requirements

(system management, recordkeeping,

etc.);

♦ excavator notification to one-call system

of intent to dig;

♦ intrastate pipeline operator participation

in one-call system;

♦ pipeline operator response to notices of

intended excavation activity (e.g., marking

location of pipeline);

♦ notification of excavators and public

availability and use of one-call system;

and

♦ authority to enforce sanctions for violation

of one-call requirements.

NARUC/NAPSR. The Department coordinates

closely with the National Association of

Regulatory Utility Commissioners (NARUC) and

the National Association of Pipeline Safety

Representatives (NAPSR). These two

organizations, representing state interests in

pipeline safety matters, hold meetings during the

year and adopt resolutions to surface pipeline

safety concerns of national significance.

NARUC is an organization of governmental

agencies engaged in the regulation of utilities

spanning the areas of communication, electricity,

energy, gas and oil, and motor carriers. The

objective of NARUC is to serve the consumer

interest by seeking to improve the quality and

effectiveness of public regulation in America.

NARUC, through its Staff Subcommittee on

Pipeline Safety under the Committee on Gas,

provides RSPA a two-way communication

channel with state public utility commissioners (or

their equivalents) and state pipeline safety

program managers. In 1993, the Subcommittee

proposed and NARUC resolved that excess flow

valves should not be required by Federal statute or

regulations but left to the discretion of each state.

NAPSR is an organization of state gas pipeline

safety program managers, inspectors, and technical

personnel who support and work to enhance

pipeline safety. Each year, NAPSR holds national

and regional meetings to promote information

exchange and innovative approaches for

implementing the pipeline safety program. During

1993, NAPSR submitted resolutions petitioning

RSPA to exempt liquefied petroleum gas (LPG)

operators from Part 199 drug testing requirements;

provide guidance on compliance with Part 198

one-call notification system requirements; develop

refresher training for state and Federal safety

inspectors; and publish Federal guidance on the

staffing formula NAPSR developed for estimating

an adequate, base-level number of state safety

inspectors.

NAPSR, from time to time, establishes working
17

Table 6

1993 Na tura l Ga s Sta te Inspe ctor Qua lifica tions

STA TE CA T I CA T II CA T III CA T IV CA T V TOTA L

AL PSC 0 8 1 0 0 9

AR PSC 0 4 0 0 0 4

AZ CC 0 11 0 0 0 11

CA PUC 5 0 9 0 0 14

CO PUC 2 0 1 0 0 3

CT DPUC 1 0 2 0 0 3

DC PSC 0 1 1 0 0 2

DE PSC 1 0 0 0 0 1

F L PSC 0 4 1 1 0 6

F L LPG 0 2 2 0 0 4

GA PSC 0 3 0 2 1 6

IA DC 2 3 0 0 0 5

IL CC 0 7 0 0 0 7

IN PSC 0 3 1 0 0 4

KS CC 2 6 1 0 0 9

KY PSC 0 4 0 0 0 4

LA DN R 0 13 0 0 0 13

MA DPU 0 4 1 0 0 5

MD PSC 1 1 1 1 0 4

MI PSC 4 0 0 0 0 4

MN OPS 4 3 1 0 0 8

MO PSC 3 4 2 0 0 9

MS PSC 0 1 1 1 0 3

MT PSC 0 1 1 0 0 2

NC UC 0 1 0 1 1 3

ND PSC 0 1 1 0 0 2

NE SFM 0 0 2 0 0 2

NH PUC 1 0 1 0 0 2

NJ BR C 2 0 2 0 0 4

NM SCC 2 1 0 0 0 3

NV PSC 1 0 2 0 0 3

NY PSC 0 16 2 3 0 21

OH PUC 1 5 1 0 0 7

OK CC 0 3 1 0 0 4

OR PUC 0 2 1 0 0 3

PA PU C 2 3 1 0 0 6

PR PSC 0 1 0 0 2 3
Table 6 (continued)

STA TE CA T I CA T II CA T III CA T IV CA T V TOTA L

RI PU C 0 0 0 0 2 2

SC PSC 0 3 0 0 0 3

TN PSC 3 1 1 0 0 5

TX RC 8 9 7 6 1 31

UT DBR 0 1 1 0 0 2

VA SCC 3 1 0 0 0 4

VT D PS 0 1 0 0 0 1

W A U TC 0 1 0 0 0 1

W I PSC 2 0 1 0 0 3

WV PSC 0 5 0 1 0 6

W Y PSC 3 0 0 0 0 3 0

TOTAL 53 138 50 16 7 264

1993 Ha za rdous Liquid S ta te Inspe ctor Qua lifica tio ns

STA TE CA T I CA T II CA T III CA T IV CA T V TOTA L

AL PSC 0 6 1 0 0 7

AZ CC 0 5 0 0 0 5

CA SFM 1 3 1 2 0 7

LA D NR 0 2 0 0 0 2

MN OPS 2 2 0 0 0 4

MS PSC 0 0 1 0 0 1

NY PSC 0 8 1 0 0 9

OK CC 0 2 0 0 0 2

TX R C 8 9 7 6 1 31

WV PSC 0 2 0 0 0 2

TOTAL 11 39 11 8 1 70

CA TEGORY :

I H av e engineering degrees f rom ac c redited engineering s c hools or are regis tered 

prof es s ional engineers , and hav e a m inim um of 3 y ears ' ex perienc e with gas or liquid

pipelines or t he enf orc em ent of pipeline s af et y regulations at s tate or F ederal lev el

In addit ion, hav e c om pleted all applic able training at TSI or receiv ed an ex em ption.

II H av e engineering degrees f rom ac c redited engineering s c hools , are regis tered prof es s ional

engineers , or hav e a m inim um of 5 y ears experience as s t at e or F ederal

pipeline ins pec tors m onitoring gas or liquid operators f or c om plianc e wit h s tate

and F ederal pipeline s af ety regulations . H av e c om pleted all applic able TS I t raining,

or hav e 10 y ears ex perienc e and hav e com pleted half t he applic able t raining.

II I H av e c ollege degrees or m inim um of 5 y ears ' ex perienc e in gas or liquid pipelines .

IV H av e les s t han 5 y ears ' experience as st at e pipeline ins pec tors .

V H av e les s t han 1 y ear ex perienc e as s tate pipeline ins pec t or.

18
19

Table 7

1993 State Agency Inspection Activity - Natural Gas

STATE OPERATOR (S) OPERATORS INSPECTION INSPECTION INSPECTORS PERSON INSPECTIONS PROBABLE COMPLIANCE INCIDENTS

INSPECTED UNITS UNITS YEARS MADE PER- VIOLATIONS ACTIONS LISTED ON

INSPECTED SON DAYS TAKEN CERT/AGR.

AL PSC 232 232 310 310 9 7.58 1,135 171 107 4

AR PSC 443 109 666 263 4 4.00 395 217 93 1

AZ CC 1,284 815 1,308 839 11 9.42 1,595 2,886 53 3

CA PUC 3,864 607 3,001 700 14 9.25 1,088 2,229 524 17

CO PUC 111 95 167 139 3 3.00 324 140 35 3

CT DPUC 9 9 32 32 3 1.25 197 51 11 6

DC PSC 1 1 5 5 2 1.30 193 3 3 3

DE PSC 11 11 15 15 1 0.40 85 2 2 0

FL PSC 61 56 79 73 6 3.68 568 71 37 4

FL LPG 81 81 376 345 4 1.36 378 389 58 0

GA PSC 221 189 263 223 6 4.63 733 59 20 1

IA DC 64 33 104 44 5 2.98 457 232 37 3

IL CC 120 90 86 139 7 6.83 581 207 62 4

IN PSC 103 103 185 162 4 3.83 512 39 20 8

KS CC 207 207 251 235 9 8.58 960 1,071 195 0

KY PSC 220 89 262 97 4 3.25 345 344 74 8

LA DNR 417 356 495 412 13 8.46 1,093 395 103 20

MA DPU 15 15 43 32 5 4.75 686 36 4 2

MD PSC 94 94 107 107 4 3.06 274 223 65 6

MI PSC 41 38 105 102 4 3.46 371 20 20 1

MN OPS 48 48 67 63 8 5.34 455 392 63 1

MO PSC 63 56 140 115 9 6.75 515 205 53 8

MS PSC 157 135 201 177 3 2.99 375 145 15 1

MT PSC 23 23 35 33 2 0.54 64 39 0 5

NC UC 39 39 87 88 3 2.58 396 131 60 0

ND PSC 25 25 30 30 2 0.73 125 26 14 0

NE SFM 26 21 52 36 2 2.00 171 80 13 0

NH PUC 8 7 15 10 2 1.25 60 15 5 1

NJ BRC 4 4 28 28 4 3.50 485 27 2 8

NM SCC 282 214 350 275 3 3.00 267 166 84 2

NV PSC 46 18 56 20 3 2.04 208 44 4 2

NY PSC 34 27 106 88 21 33.58 3,612 1,023 201 2

OH PUC 312 72 445 128 7 6.42 810 60 26 4

OK CC 182 105 250 142 4 4.00 420 964 141 4

OR PUC 13 13 19 19 3 2.35 210 636 31 0

PA PUC 43 43 133 133 6 5.50 782 371 73 8

PR PSC 1 1 2 2 3 1.25 92 3 0 0
1993 State Agency Inspection Activities - Hazardous Liquid

STATE OPER- OPERATORS INSPECTION INSPECTION INSPEC- PERSON INSPECTIONS PROBABLE COMPLIANCE INCIDENTS

ATOR INSPECTED UNITS UNITS TORS YEARS MADE PER- VIOLATIONS ACTIONS LISTED ON

(S) INSPECTED SON DAYS TAKEN CERT/AGR.

AL PSC 3 3 3 3 7 0.19 22 1 1 0

AZ CC 6 6 7 7 5 0.90 107 7 3 1

CA SFM 84 53 111 78 7 5.58 496 100 25 9

LA DNR 31 31 43 41 2 1.85 175 237 19 1

MN OPS 8 8 17 12 4 1.45 145 35 1 2

MS PSC 2 2 2 2 1 0.001 7 5 0 0

NY PSC 4 2 4 2 9 0.46 32 1 1 0

OK CC 11 11 21 12 2 1.17 122 126 14 5

TX RC 138 97 229 152 31 3.91 383 333 91 4

WV PSC 1 1 1 1 2 0.21 21 0 0 0

TOTAL 288 214 438 310 70 15.72 1,510 845 155 22

 Some of these inspectors also inspect gas pipeline operators and are also counted in the complement of 264 gas inspectors.

20

Table 7 (continued)

STATE OPERATOR (S) OPERATORS INSPECTION INSPECTION INSPECTORS PERSON INSPECTIONS PROBABLE COMPLIANCE INCIDENTS

INSPECTED UNITS UNITS YEARS MADE PERSON VIOLATIONS ACTIONS LISTED ON

INSPECTED DAYS TAKEN CERT/AGR.

RI PUC 14 7 19 12 2 1.01 209 8 8 1

SC PSC 32 32 44 44 3 2.80 489 300 70 1

TN PSC 189 189 209 208 5 4.10 454 373 114 0

TX RC 1,555 759 1,983 1,039 31 22.16 2561 3,660 744 14

UT DBR 537 150 573 157 2 2.00 240 138 37 0

VA SCC 9 9 31 31 4 2.95 332 20 14 2

VT DPS 40 26 40 17 1 0.80 98 15 5 0

WA UTC 25 13 43 20 1 1.00 87 157 2 1

WI PSC 15 15 61 26 3 1.59 89 113 13 1

WV PSC 204 113 230 137 6 5.19 630 16 6 11

WY PSC 49 36 70 38 3 1.71 149 25 25 1

Total 11,574 5,430 13,179 7,390 264 220.20 26,355 17,937 3,346 172
committees to tackle particular problems or

undertake projects where RSPA wants state input.

During the year, the NAPSR Liaison Committee

completed a review of Part 192 to identify

regulations that need to be more explicit,

understandable, and enforceable. The committee’s

final report targets the 20 highest priority issues

requiring revision from the state perspective.

RSPA plans to publish the report in the Federal

Register seeking public comment on the proposed

changes.

The Over/Under Estimating Committee met in

1992 to continue its assessment of the disparity

between state estimated and actual year-end

program costs (excessive “carryover” grant funds

had been flagged as a problem by the Secretary’s

Safety Review Task Force in 1989). The

committee found progress had been made in

reducing excessive estimates and will meet again

in two years to see if any additional measures need

to be instituted. During the year, the Grant

Allocation Committee also met to discuss changes

to performance factors used in the grant allocation

formula.

Achieving operator compliance with the pipeline

21
safety regulations is critical to preventing

accidents. Accordingly, RSPA has increased

emphasis on those components of the overall

pipeline safety programs which contribute

significantly to compliance, including operator

inspections, compliance actions, state oversight,

and accident investigations. The five pipeline

safety Regional Offices constitute the backbone of

RSPA’s compliance efforts. Our continued efforts

to decentralize allow RSPA to be more responsive

to operational problems. This leads to improved

regional/operator relations, more efficient

utilization of resources, and ready availability of

expertise to address unique state/regional safety

and environmental concerns.

Risk-Based Pipeline Inspection Plan. The most

fundamental way to achieve compliance is

through periodic inspection of pipeline operations.

RSPA regional staff inspect interstate gas and

hazardous liquid pipeline systems, as well as the

intrastate facilities under direct Federal jurisdiction,

such as certain municipal and master meter gas

systems that are not regulated by a state agency, or

intrastate gas and liquid facilities in states where a

state agency is not participating in the program.

RSPA continued to use its risk-based pipeline

inspection plan for scheduling unit inspections

prioritized by risk. In determining the priority of

inspections, RSPA considers existing safety

problems; population density; known

environmental sensitivity of unit areas; results of

past inspections; analysis of safety-related

condition reports filed by operator; length of time

since last inspection; and Pipeline Inspection

Priority Program (PIPP) rankings.

PIPP rankings are based upon operator-supplied

information such as proportion of pipeline without

corrosion protection, leak repair history, and

pipeline material (cast iron pipe and poly vinyl

chloride (PVC) and acrylonitrile-butadiene-styrene

(ABS) plastic pipe present greater risk). PIPP

rankings also reflect RSPA inspection results and

enforcement actions.

The risk-based inspection plan enables Regional

Offices to allocate their limited inspection

resources based on risk. It also has built-in

flexibility which allows RSPA to devote more

time to such critical activities as new construction

follow-up, drug testing inspections, and additional

accident investigations.

Inspection Activity. In 1993, RSPA’s regional

staff expended a total of 809 person-days

inspecting 180 natural gas and 162 hazardous

liquid inspection units (see Table 8 on page 23).

Compliance Actions. RSPA has various

compliance actions available to address a probable

violation of the pipeline safety regulations. These

actions, depending on the circumstances, range

from issuing a warning letter to issuing a

hazardous facility order requiring immediate

suspension of operations or restricted use of a

facility.

In 1993, RSPA opened 179 compliance actions,

referenced in Appendices A and C, with proposed

civil penalties recommending assessments totaling

$1,217,300 against gas and hazardous liquid

pipeline operators found to be in violation of the

pipeline safety regulations.

In 1993, final disposition of 73 Compliance

Progress Files (CPFs), one decision on a petition

of reconsideration, and two amendments to

hazardous facility orders resulted in three consent

orders, seven hazardous facility orders, and 57

civil penalties assessing a total of $748,150 for

violations of the pipeline safety regulations.

In 1993, RSPA closed 143 CPFs referenced in

Appendix B and collected penalties totaling

$462,000.

Accident Investigations and State Oversight.

22

COMPLIANCE
RSPA staff investigate selected pipeline accidents

to determine if the regulations have been violated

and whether revisions or additions to the

regulations are needed. During 1993, RSPA staff

expended 352 person-days conducting 49 accident

investigations and following up on 10 public

complaints.

In addition to inspecting interstate pipeline

operators, RSPA regional staff also oversee the

intrastate natural gas and hazardous liquid pipeline

safety programs of state agencies participating in

the Federal/State program, as well as the programs

of those state agencies acting as agents for RSPA

to inspect interstate operators.

The requirements and criteria for reporting gas

23

 

Table 8

1993 Inspection and Compliance Profile 

Inspection Profile 

Program # Inspection Units Inspected Person Days Spent 

on Inspections

OPS Hazardous Liquid 162 394

OPS Natural Gas 180 415

State Hazardous Liquid 310 1,510

State Natural Gas 7,371 26,266

Compliance Actions Taken

Compliance Compliance Hazardous Facility Penalties Collected

 Program Action Orders Orders Issued No. Amount

Initiated Issued

 OPS Hazardous Liquid 78 18 5

 Liquid/Gas Penalties Combined 57 $748,150

 OPS Natural Gas 94 22 2

 State Hazardous Liquid 155 N/A N/A 9 $95,500

 State Natural Gas 3,346 N/A N/A 29 $418,410

Detail of State Penalty Data

State Penalties Collected State Penalties Collected State Penalties Collected

# $ AMT. # $ AMT. # $ AMT.

 California * 8 95,000 Maryland 2 30,000 Ohio 4 165,460

 Colorado 2 30,500 Massachusetts 8 140,250 Pennsylvania 1 1,200

 Louisiana 3 3,500 Minnesota 5 14,000 Tennessee 2 23,000

 Louisiana * 1 500 Missouri 1 10,000 Texas 1 500

Total 38 513,910

 * Liquid
Table 10

1993 Natural Gas Distribution Pipeline

Incidents Reported by Cause

Cause Incidents Property Fatalities Injuries

Damage

Accidently Caused by Operator 9 $117,000 0 9

Construction/Material Def ect 8 $701,000 0 6

Damage by Outside Forces 73 $11,490,555 11 35

External Corrosion 7 $195,100 2 10

Internal Corrosion 0 $0 0 0

Other 24 $2,843,000 3 24

Total 121 $15,346,655 16 84

pipeline incidents are contained in 49 CFR Part

191. Subpart B of Part 195 includes regulations

for reporting hazardous liquid pipeline accidents.

These regulations define damage thresholds,

exclusions, time requirements, and reporting

methods. RSPA

maintains data

reported by pipeline

operators on

incidents and

accidents in the

Integrated Pipeline

Information System

(IPIS). IPIS is the

primary tool for

storing, retrieving,

and analyzing

pipeline safety

data. IPIS provides

operational and

statistical information necessary to perform

failure and cost-benefit analyses and various

other studies supporting rulemaking,

enforcement, and research.

Natural Gas Pipeline Incident Data. Criteria

for the submission of written incident reports by

natural gas distribution, transmission, and

gathering operators were revised, effective July

1, 1984. This revision requires reports on all

incidents, regardless of the size of the operator,

involving a release of gas and either:

(1) a death or personal injury necessitating inpatient hospitalization, or (2)

estimated property

damage of

$50,000 or more.

Reports are not

required for

master meter

systems or LNG

facilities.

During 1993,

natural gas

transmission and

ACCIDENTS AND INVESTIGATIONS

24

Table 9

1993 Natural Gas Transmission and

Gathering Pipeline Incidents Reported by Cause

Cause Incidents Property Fatalities Injuries

Damage

Construction/Material Defect 15 $6,704,834 0 1

Damage by Outside Forces 36 $9,335,558 0 2

External Corrosion 9 $1,400,876 0 1

Internal Corrosion 6 $1,657,000 0 0

Other 30 $3,937,000 1 14

Total 96 $23,035,268 1 18

gathering pipeline operators reported 96 incidents,

involving one fatality, 18 injuries, and $23,035,268

of property damage (see Table 9). Natural gas

distribution pipeline operators reported 121

incidents, resulting in 16 fatalities, 84 injuries, and

$15,346,655 of property damage (see Table 10).

Of the 217 total gas incidents, 109 (50 percent)

were attributed to damage by outside forces.

This is an increase from 1992, when 48 percent of

all gas incidents were caused by outside force

damage.

Total gas failures, fatalities, and injuries that
25

0

20

40

60

80

100

120

102 89 71 74 96

22 0 0 3 1

28 17 12 15 18

Year 1989 1990 1991 1992 1993

Failures

Fatalities

Injuries

T a ble 11

Summary of Natural Gas Transmission & Gathering Pipeline Failures, Fatalities, and Injuries (1989-1993)

0

50

100

150

200

177 109 162 103 121

20 6 14 7 16

91 52 77 65 84

Year 1989 1990 1991 1992 1993

Failures

Fatalities

Injuries

T a ble 12

Summary of Natural Gas Distribution Pipeline Failures, Fatalities, and Injuries (1989-1993)
26

total of 230 accidents, resulting in no fatalities, 10

injuries, $28,873,651 of property damage, and a

release of 119,002 barrels of product. Of the 230

hazardous liquid accidents, 59 (25 percent) were

attributed to damage by outside forces (see Table

14 on page 27) and 55 (24 percent) were attributed

to corrosion (external and internal).

Hazardous liquid accidents were somewhat higher

in 1993 than the average of the preceding four

years (230 vs. 193). Fatalities and injuries

registered a decrease in 1993 over the average of

the preceding four years (3 vs. 0 and 23 vs. 10,

respectively) (see Table 13 below). Crude oil, the

commodity spilled most often, accounted for 37

percent of all reported hazardous liquid accidents

but caused 25 percent of all property damage

associated with those accidents (see Table 15 on

page 27).

Economic Impact of Accidents. RSPA converts

occurred in 1993 reflect the average of the

preceding four years (217) (see Tables 11 and 12

on page 25).

Hazardous Liquid Pipeline Accident Data. On

October 21, 1985, the accident reporting

requirements for hazardous liquid pipeline

operators were revised to include interstate and

intrastate operators. The definition of a reportable

accident for hazardous liquids was not affected by

this revision i.e., a release of hazardous liquid

transported and either: (1) an explosion or fire not

intentionally set by the operator, (2) loss of 50 or

more barrels of product, (3) escape to the

atmosphere of more than five barrels a day of

highly volatile liquid (HVL), (4) death or bodily

harm to any person, or (5) estimated property

damage exceeding $50,000. During 1993,

hazardous liquid pipeline operators reported a

0

50

100

150

200

250

163 180 216 212 230

33050

38 7 9 38 10

Year 1989 1990 1991 1992 1993

Failures

Fatalities

Injuries

T a ble 13

Summary of Hazardous Liquid Pipeline Failures, Fatalities, and Injuries (1989-1993) 
27

which written reports were submitted to the

Department in 1993, some are of particular interest

given environmental implications, extent of

property damage, or cause of accident.

Unusually heavy snowfall accumulations

accident data to a common denominator for

purposes of preparing cost-benefit justifications in

rulemakings and for assessing risk. The economic

impact of injuries, fatalities, and barrels of product

spilled is calculated using a dollar equivalent--

$450,000 is used for each injury, $2,500,000 for

each fatality, and $25 for

each barrel of product spilled.

These dollar equivalents for

injuries and fatalities are

based on a Department

analysis of economic studies

of the “willingness-to-pay”

concept. Property damage is

shown at the dollar level

reported by the pipeline

operator. Based on these

dollar equivalents, the 217

natural gas and 230 hazardous

liquid pipeline accidents

reported to RSPA in 1993

accounted for a combined

economic impact of

$144,494,274 in injuries,

fatalities, product spilled,

and property damage (see

Table 16 on page 28).

Accidents of Interest. Of

the pipeline accidents for

Table 14

Hazardous Liquid Pipeline Accidents Reported by Cause

Cause Accidents Barrels Property Fatalities Injuries

Lost Damage

Equipment Malfunction 17 6,915 $580,200 0 0

External Corrosion 41 3,498 $2,996,820 0 0

Failed Pipe 10 7,277 $1,923,000 0 0

Failed Weld 7 8,497 $3,252,054 0 0

Incorrect Operation 15 19,271 $731,445 0 4

Internal Corrosion 14 1,455 $123,428 0 0

Other 67 27,140 $4,741,055 0 5

Outside Force Damage 59 44,949 $14,525,649 0 1

Total 230 119,002 $28,873,651 0 10

Table 15

Summary of Liquid Pipeline Accidents Reported by Commodity

Commodity # % of Total Barrels Property % of Total Fatalities Injuries

Incidents Lost Damage

Anhydrous Ammonia 5 2.17 12,458 $424,376 1.47 0 6

Condensate 1 0.43 50 $983,000 3.4 0 0

Crude Oil 86 37.39 45,100 $7,315,318 25.34 0 2

Diesel Fuel 15 6.52 3,548 $1,626,500 5.63 0 0

Fuel Oil 14 6.09 12,172 $10,670,000 36.95 0 0

Gasoline 59 35.65 26,339 $5,177,095 17.93 0 0

Jet Fuel 9 3.91 865 $165,977 0.57 0 0

Kerosene 3 1.3 76 $58,600 0.2 0 0

L.P.G. 13 5.65 10,816 $276,821 0.96 0 2

Natural Gas Liquid 7 3.04 5,669 $142,482 0.49 0 0

Oil and Gasoline 7 3.04 396 $401,000 1.39 0 0

Turbine Fuel 1 0.43 5 $20,000 0.07 0 0

Various Petrol Prod 3 1.3 1,040 $49,500 0.17 0 0

Not Given 7 3.04 468 $1,562,982 5.41 0 10

Total 230 99.96 119,002 $28,873,651 99.98 0 10
0 50 100 150 200

$144,494,274

$67,141,574

$50,400,000

$25,500,000

$1,452,700

$34,826,351

$77,032,655

$32,635,268

Millions

Dollar Amount in

Total Damages

Property Damage

Injuries

Fatalities

Product Spilled

Hazardous Liquid Accidents

Gas Distribution Incidents

Gas Transmission & Gathering Incidents

Table 16

1993 Economic Impact of Pipeline Accidents *

*Conversion f actor f or calculating economic impact: $450,000 per injury; $2,500,000 per death;

$25 per barrel of product spilled (hazardous liquid only ).

28
precipitated five propane incidents in California.

On January 18, an explosion and fire occurred at

the Pine Tree Apartments in Chester, CA. It was

determined that snow/ice shoveled from the roof

of the Pine Tree Apartments damaged the propane

meter set, allowing propane to migrate into a crawl

space below the apartment. In addition to one

fatality and nine injuries, significant property

damage was reported. It was determined that the

operator, Amerigas, did not have adequate

procedures or appropriately trained employees, to

respond to a leak, a complaint, or an emergency.

On January 20, 1993, two persons were killed and

five injured when an explosion and fire occurred at

the Sun Meadows II condominium in Kirkwood,

CA. Significant structural damage prevented

determination of the exact cause of the explosion,

but it is believed that snow may have slid off of the

sloped roof onto the meter set, damaging it.

Three other propane incidents, involving nonjurisdictional facilities, were noted by the OPS. To

reduce the possibility of further snow related

incidents, OPS issued a Pipeline Safety Advisory

ADB-93-01 (Snow Accumulation of Gas Pipeline

Facilities - 58 FR 7034; February 3, 1993).

On March 28, 1993, Colonial Pipeline Company

experienced a release of 8,000 barrels of diesel fuel

on its 36-inch products pipeline, near Reston, VA.

The released product entered the Sugarland Run, a

tributary to the Potomac River. Approximately

7,392 barrels of product were recovered by a series

of containment barriers. An unknown amount of

product entered the Potomac River, resulting in the

closure of the Fairfax County water intake. This

section of the pipeline transports products from

Chantilly, VA to Dorsey Junction, MD and carries

approximately 28 percent of all products shipped

to the northeastern states. Approximately 41 local

residents voluntarily evacuated their homes. Third

party excavation damage from prior years is

believed to have precipitated the failure.

The OPS assisted the New Jersey Board of

Regulatory Commissioners and the National

Transportation Safety Board (NTSB) in their June

10 investigation of an Aberdeen Township, NJ

incident. Three fatalities and three serious injuries

occurred after a New Jersey natural gas contractor

struck a service line during construction of a new

gas main. Upon realizing he had struck a gas

service line, the contractor excavated and repaired

the line where it had pulled away from the main.

After an explosion consumed a nearby house, a

second failure on the service line was discovered.

It was determined that gas migrated from the

second failure site into the lower level of the house,

providing fuel for the subsequent explosion and

fire.

Assistance was given to the District of Columbia

and the NTSB during investigation of a June 28,

Washington, D.C. incident. The incident, which

resulted in one fatality and four injuries, occurred

when gas ignited from a leaking 12-inch cast iron

pipe. Evidence at the site indicates that installation

of a light pole located inches from the Washington

Gas Light Company main may have damaged the

cast iron pipe.

Three fatalities and twelve injuries occurred in St.

Paul, MN, after sewer workers struck a plastic

natural gas service line. The explosion and fire,

which caused significant property damage to

nearby structures, occurred approximately twenty

minutes after a backhoe operator struck the

pipeline. The OPS assisted the Minnesota Office

of Pipeline Safety and the NTSB in the

investigation of the July 22 explosion.

On August 14, 1993, Columbia Gas Transmission’s

12-inch bare steel pipeline ruptured near the

airport at Binghamton, NY. The cause of the

failure was corrosion. While there were no

fatalities or injuries, one home was totally

destroyed. RSPA and the New York Public

Service Commission, acting as an interstate agent,

investigated the integrity of this line under the

authority of a Hazardous Facility Order.

On August 24, 1993, Columbia Gulf Transmission

29
Company’s 24-inch looped natural gas line

crossing the Mississippi River ruptured. There

were no casualties and the line was isolated with

the closure of automatic valves. Delivery of gas

was not affected since multiple line crossings are

in the area. A boat was reported to have been

observed “stationary” in the river, indicating the

possibility an anchor may have been involved. At

the time of the incident, there was high water in

this region making it impossible to assess the

damage.

On August 30, 1993, company forces, while

investigating an anomaly shown on the Vetco

Smart Pig log, discovered a leak on a 40-inch line

near Pineville, Louisiana. The line was flowing

gasoline at 100 psig. The leak occurred in a dent

with a 2-inch crack at the 8 o’clock position on the

pipe. It was not feasible to cut out the damaged

pipe so the line was repaired using a weldover

sleeve and returned to service on August 31.

On September 18 and on November 4, 1993,

Columbia Gas Transmission experienced ruptures

due to internal corrosion in drips on storage field

lines associated with two separate storage fields.

No fatalities or injuries resulted, but gas was

released in both incidents and ignited into large

fireballs. As a result of these incidents, RSPA

issued a Hazardous Facility Order to Columbia.

The order required Columbia to test and analyze

fluids from all 11 storage fields in West Virginia.

Based on the analysis, Columbia initiated short

and long-term remedial actions. Columbia has

revised their operating and maintenance procedures

relating to internal corrosion on a company-wide

basis. The West Virginia Public Service

Commission, acting as an interstate agent, ensured

that the terms of the Hazardous Facility Order

were carried out.

A special investigation of CNG Transmission

Company was initiated on June 28, 1993, because

the OPS Eastern Region and the West Virginia

Public Service Commission found probable

30

violations pertaining to corrosion control in

various CNG inspection units. A specialized

comprehensive evaluation of CNG’s corrosion

records was made on a company-wide basis. Two

interstate agents, Ohio and West Virginia, assisted

the Eastern Region. The OPS Central Region

coordinated with the Ohio Public Utility

Commission. The investigation resulted in

violations and a civil penalty of $130,000.

On November 15, 1993, Transcontinental Gas

Pipe Line Corporation’s (Transco) Line A, a 30-

inch gas transmission pipeline, experienced a

blow-out approximately 17 miles downstream of

their El Campo, Texas, main line compressor

station. The failure occurred at an estimated

pressure of 740 psig. The blowing gas was ignited

by an unknown source. The failure occurred in an

open field; there were no fatalities, injuries, or

property damages other than an area scorched by

the fire. The failed section was isolated, including

offshore Texas Gulf of Mexico gas production that

the pipeline was transporting.

On December 11, 1993, vapors from natural gas

condensate, released during liquid removal

operations, ignited. The resulting combustion

caused injuries which required the hospitalization

of two Transco employees and one Fescue

(Transco contractor) employee. Following the

ignition, valves at the separator were immediately

closed to halt the pipeline liquid removal

operation. Secondary fires were then extinguished.

Local emergency services personnel arrived at the

site and all injured personnel were evacuated by

helicopter. The five frac tanks (portable, nonpressurized, steel storage tanks) were emptied and

all remaining natural gas condensate was trucked

to a processing plant near Pearsall, Texas.

NTSB Safety Recommendations. On December
31

15, 1993, NTSB issued a formal safety

recommendation (P-93-009) following an April 7,

1992, release of HVLs from a salt dome storage

cavern in the Seminole Pipeline system near

Brenham, Texas. Three fatalities, 21 injuries, and

over nine million dollars of property damage

resulted from the incident. NTSB recommended

that the RSPA develop safety requirements for

storage of highly volatile liquids (HVLs) and

natural gas in underground facilities, including a

requirement that all pipeline operators perform

safety analyses of new and existing underground

geologic storage systems to identify potential

failure. Additionally, NTSB recommended that a

determination be made as to the likelihood that

each failure will occur; assess the feasibility of

reducing the risk of failure; and require that

operators incorporate all feasible improvements.