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EXHIBIT B

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Pacific Gas and Electric Company

Natural Gas Transmission Pipeline Rupture and Fire

San Bruno, California

September 9, 2010

Accident Report

NTSB/PAR-11/01

PB2011-916501 National 

Transportation 

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NTSB/PAR-11/01

PB2011-916501

Notation 8275C

Adopted August 30, 2011

Pipeline Accident Report

Pacific Gas and Electric Company

Natural Gas Transmission Pipeline Rupture and Fire

San Bruno, California

September 9, 2010

National 

Transportation 

Safety Board

490 L’Enfant Plaza, S.W.

Washington, DC 20594

Case: 19-30088 Doc# 2028-2 Filed: 05/15/19 Entered: 05/15/19 16:58:06 Page 3

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National Transportation Safety Board. 2011. Pacific Gas and Electric Company Natural Gas 

Transmission Pipeline Rupture and Fire, San Bruno, California, September 9, 2010. Pipeline 

Accident Report NTSB/PAR-11/01. Washington, DC.

Abstract: On September 9, 2010, about 6:11 p.m. Pacific daylight time, a 30-inch-diameter segment of 

an intrastate natural gas transmission pipeline known as Line 132, owned and operated by the Pacific Gas 

and Electric Company, ruptured in a residential area in San Bruno, California. The rupture occurred at 

mile point 39.28 of Line 132, at the intersection of Earl Avenue and Glenview Drive. The rupture 

produced a crater about 72 feet long by 26 feet wide. The section of pipe that ruptured, which was about 

28 feet long and weighed about 3,000 pounds, was found 100 feet south of the crater. The Pacific Gas and 

Electric Company estimated that 47.6 million standard cubic feet of natural gas was released. The 

released natural gas ignited, resulting in a fire that destroyed 38 homes and damaged 70. Eight people 

were killed, many were injured, and many more were evacuated from the area.

As a result of its investigation of this accident, the National Transportation Safety Board makes 

recommendations to the U.S. Secretary of Transportation, the Pipeline and Hazardous Materials Safety 

Administration, the governor of the state of California, the California Public Utilities Commission, the 

Pacific Gas and Electric Company, the American Gas Association, and the Interstate Natural Gas 

Association of America.

The National Transportation Safety Board is an independent Federal agency dedicated to promoting aviation, 

railroad, highway, marine, pipeline, and hazardous materials safety. Established in 1967, the agency is mandated by 

Congress through the Independent Safety Board Act of 1974 to investigate transportation accidents, determine the 

probable causes of the accidents, issue safety recommendations, study transportation safety issues, and evaluate the 

safety effectiveness of government agencies involved in transportation. The Safety Board makes public its actions 

and decisions through accident reports, safety studies, special investigation reports, safety recommendations, and 

statistical reviews.

Recent publications are available in their entirety on the Internet at <http://www.ntsb.gov>. Other information about 

available publications also may be obtained from the website or by contacting:

National Transportation Safety Board

Records Management Division, CIO-40

490 L’Enfant Plaza, SW

Washington, DC 20594

(800) 877-6799 or (202) 314-6551

Safety Board publications may be purchased, by individual copy or by subscription, from the National Technical 

Information Service. To purchase this publication, order report number PB2011-916501 from:

National Technical Information Service

5301 Shawnee Road

Alexandria, Virginia 22312

(800) 553-6847 or (703) 605-6000

The Independent Safety Board Act, as codified at 49 U.S.C. Section 1154(b), precludes the admission into evidence 

or use of Board reports related to an incident or accident in a civil action for damages resulting from a matter 

mentioned in the report.

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iii

Contents

Figures........................................................................................................................................... vi

Tables........................................................................................................................................... vii

Acronyms and Abbreviations................................................................................................... viii

Executive Summary.......................................................................................................................x

Investigation Synopsis.....................................................................................................................x

Probable Cause.............................................................................................................................. xii

Recommendations......................................................................................................................... xii

1. Factual Information...................................................................................................................1

1.1 Accident Narrative .....................................................................................................................1

1.1.1 Preaccident Events...........................................................................................................3

1.1.2 Events Leading Up to Rupture ........................................................................................5

1.1.3 The Rupture ...................................................................................................................12

1.2 Emergency Response ...............................................................................................................12

1.3 Injuries .....................................................................................................................................18

1.4 Damage ....................................................................................................................................18

1.5 Meteorological Information.....................................................................................................21

1.6 Personnel Information..............................................................................................................21

1.6.1 Milpitas Technician and Other Workers at the Milpitas Terminal................................21

1.6.2 SCADA Operators.........................................................................................................22

1.7 Pipeline Information ................................................................................................................23

1.7.1 Line 132 .........................................................................................................................23

1.7.2 1956 Relocation Project (Segment 180)........................................................................25

1.7.3 Multiyear Replacement Project and Seismic Risk.........................................................29

1.7.4 Underground Environment at Accident Location..........................................................30

1.7.4.1 2008 Sewer Replacement.................................................................................30

1.7.4.2 Guidelines for Pipe Bursting............................................................................33

1.7.4.3 Pipe Bursting Study .........................................................................................33

1.7.5 Pipeline MAOP..............................................................................................................33

1.7.5.1 “Grandfather Clause”.......................................................................................34

1.7.5.2 MAOP for Line 132.........................................................................................35

1.7.5.3 Periodic Pressure Increases to MAOP .............................................................36

1.7.6 History of Seam Defects in PG&E Gas Transmission Pipelines...................................38

1.7.7 Protection Against Accidental Overpressure.................................................................39

1.8 Examination of Accident Pipe .................................................................................................39

1.8.1 Welds.............................................................................................................................41

1.8.2 Crack Initiation ..............................................................................................................43

1.8.3 Material Properties.........................................................................................................46

1.8.4 Historical Information About Steel Grades...................................................................47

1.8.5 Burst Pressure Study and Finite Element Modeling......................................................48

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1.9 Pipeline Operations and Management .....................................................................................51

1.9.1 SCADA System Operations ..........................................................................................51

1.9.1.1 Milpitas Terminal.............................................................................................52

1.9.1.2 Work Clearance Procedures.............................................................................54

1.9.1.3 Emergency Response Procedures....................................................................55

1.9.2 Use of Automatic Shutoff Valves and Remote Control Valves....................................56

1.9.3 Public Awareness...........................................................................................................57

1.9.4 PG&E Risk Management/Integrity Management Program...........................................59

1.9.4.1 Geographic Information System......................................................................59

1.9.4.2 Risk Management Procedures..........................................................................61

1.9.4.3 Threats Identified for Line 132........................................................................65

1.10 Oversight................................................................................................................................67

1.10.1 State Oversight by CPUC............................................................................................67

1.10.2 Federal Oversight by PHMSA.....................................................................................69

1.11 Postaccident Actions..............................................................................................................71

1.11.1 Actions Taken by PG&E .............................................................................................71

1.11.2 Actions Taken by CPUC .............................................................................................72

1.11.3 Actions Taken by PHMSA..........................................................................................74

1.11.4 Actions Taken by Congress.........................................................................................74

1.12 Previous NTSB Safety Recommendations ............................................................................75

1.12.1 January 3, 2011, Safety Recommendations to PG&E, CPUC, and 

PHMSA Regarding Record-keeping and Hydrostatic Pressure Testing ................................75

1.12.2 June 8, 2011, Safety Recommendations to PHMSA and PG&E 

Concerning Emergency Response ..........................................................................................77

1.12.3 Other Relevant Recommendations..............................................................................78

1.12.3.1 Grandfathering of Higher Permissible Stress Levels for Pre1970 Pipelines..............................................................................................................78

1.12.3.2 Constructing and Modifying Pipelines to Accommodate Use 

of In-Line Inspection Equipment.................................................................................79

1.12.3.3 Rapid Shutdown and ASVs and RCVs..........................................................80

1.13 Other Information ..................................................................................................................81

1.13.1 Pipeline Assessment Methods for Integrity Management...........................................81

1.13.1.1 Pressure Testing.............................................................................................82

1.13.1.2 In-line Inspection ...........................................................................................83

1.13.1.3 Direct Assessment..........................................................................................85

1.13.2 Automatic Shutoff Valve Technology.........................................................................86

1.13.3 2008 Natural Gas Explosion in Rancho Cordova, California......................................87

2. Analysis.....................................................................................................................................88

2.1 Introduction..............................................................................................................................88

2.2 Preaccident Events...................................................................................................................90

2.2.1 Work Clearance Procedures for Electrical Work at Milpitas Terminal ........................90

2.2.2 Internal Line Pressure Prior to Failure...........................................................................91

2.3 Cause of Pipeline Rupture .......................................................................................................92

2.3.1 Fracture Origin and Failure ...........................................................................................93

2.3.2 Deficiencies in Fabrication of Accident Pipe Segment .................................................94

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2.3.3 Deficiencies in Quality Control Associated with 1956 Relocation 

Project.....................................................................................................................................95

2.3.4 2008 Sewer Pipe Bursting Operation ............................................................................96

2.4 Adequacy of PG&E Emergency Response..............................................................................97

2.4.1 Internal Communication and Coordination ...................................................................98

2.4.2 Notifying Emergency Responders...............................................................................100

2.4.3 Line Break Recognition...............................................................................................101

2.4.4 Rapid Shutdown, ASVs, and RCVs ............................................................................102

2.4.5 Deficiencies in Postaccident Drug and Alcohol Testing .............................................104

2.5 MAOP....................................................................................................................................106

2.5.1 MAOP of Line 132 ......................................................................................................106

2.5.2 Grandfathering of Pre-1970 Pipelines.........................................................................106

2.6 Integrity Management Program.............................................................................................107

2.6.1 PG&E GIS and Pipeline Record-keeping....................................................................108

2.6.2 Threat Identification and Risk Assessment .................................................................110

2.6.2.1 Weighting of Threats .....................................................................................110

2.6.2.2 Identification and Assessment of Design/Material and 

Construction Threats on Line 132..............................................................................110

2.6.2.3 Regulatory Assumption of Stable Manufacturing- and 

Construction-Related Defects.....................................................................................112

2.6.3 Self-Assessment of Program Effectiveness.................................................................113

2.6.4 Summary of PG&E Integrity Management Practices..................................................114

2.7 Adequacy of PG&E’s Public Awareness Program Evaluation..............................................115

2.8 Summary of PG&E Practices.................................................................................................116

2.9 Inspection Technology...........................................................................................................118

2.10 Oversight..............................................................................................................................119

2.10.1 Performance-Based Safety Programs........................................................................119

2.10.2 Authority and Enforcement .......................................................................................122

3. Conclusions.............................................................................................................................124

3.1 Findings..................................................................................................................................124

3.2 Probable Cause.......................................................................................................................127

4. Recommendations..................................................................................................................128

4.1 New Recommendations.........................................................................................................128

4.2 Previously Issued Recommendations ....................................................................................132

4.3 Previously Issued Recommendations Classified in This Report ...........................................134

5. Appendix.................................................................................................................................140

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Figures

Figure 1. Picture of crater and ruptured pipeline. .......................................................................... 2

Figure 2. Picture of ejected pipe section........................................................................................ 2

Figure 3. Aerial view of fire........................................................................................................... 3

Figure 4. Overview of Line 132..................................................................................................... 4

Figure 5. Picture of local control panel.......................................................................................... 6

Figure 6a. Normal electrical configuration at the Milpitas Terminal............................................ 7

Figure 6b. Temporary electrical configuration at the Milpitas Terminal preceding 

the accident. .................................................................................................................................... 8

Figure 7. Schematic showing regulating valve control.................................................................. 8

Figure 8a. Valve configuration at the Milpitas Terminal prior to 5:22 p.m. ............................... 10

Figure 8b. Valve configuration at the Milpitas Terminal about 5:25 p.m................................... 11

Figure 9. Firefighters approaching accident scene....................................................................... 13

Figure 10. Location of valve closures.......................................................................................... 17

Figure 11. Picture showing area of damage from blast and fire. ................................................. 19

Figure 12. Picture of destroyed houses. ....................................................................................... 20

Figure 13. Picture of a burned car in front of several destroyed houses...................................... 20

Figure 14. Map showing PG&E peninsula gas transmission lines. ............................................. 24

Figure 15. Line 132 installation, relocations, and replacements.................................................. 26

Figure 16. Sketch of underground utilities environment. ............................................................ 30

Figure 17. Diagram of excavations relative to Segment 180....................................................... 32

Figure 18. Schematic of accident pipe. ........................................................................................ 40

Figure 19a. Picture showing cross section of longitudinal seam in pup 1................................... 42

Figure 19b. Picture showing cross section of longitudinal seam in typical DSAW 

pipe................................................................................................................................................ 42

Figure 20. Picture of pipe section with white arrows showing direction of crack 

propagation. .................................................................................................................................. 44

Figure 21. Pictures highlighting rupture initiation site in pup 1 longitudinal seam..................... 45

Figure 22a. Stress contours at an internal pressure of 375 psig for the finite 

element model of the weld geometry similar to pup 1. Contour values are the 

same as in figure 22b. ................................................................................................................... 50

Figure 22b. Stress contours at an internal pressure of 375 psig for the finite 

element model of a DSAW seam. Contour values are the same as in figure 22a......................... 50

Figure 23. Flowchart of PG&E’s emergency response procedures. ............................................ 55

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Tables

Table 1. Injuries............................................................................................................................ 18

Table 2. PG&E gas transmission pipeline seam leaks or test failures, 1948–2011. .................... 39

Table 3. Average and standard deviation of mechanical test data for all lengths of 

pipe................................................................................................................................................ 46

Table 4. Minimum yield strength, tensile strength, and elongation requirements 

according to PG&E and API pipe specifications.......................................................................... 47

Table 5. Incoming and outgoing lines at Milpitas Terminal........................................................ 53

Table 6. Survey postcard responses to public awareness brochures............................................ 59

Table 7. PG&E’s reportable events by cause for 2004–2010. ..................................................... 65

Table 8. Line 132 risk values. ...................................................................................................... 66

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Acronyms and Abbreviations

AGA American Gas Association

ANPRM advance notice of proposed rulemaking

API American Petroleum Institute

ASME American Society of Mechanical Engineers

ASOS Automated Surface Observing System

ASTM American Society for Testing and Materials

ASV automatic shutoff valve

CFR Code of Federal Regulations

COF consequence of failure

Consolidated Western Consolidated Western Steel Corporation

CPUC California Public Utilities Commission

DOT U.S. Department of Transportation

DSAW double submerged arc welded

ECDA external corrosion direct assessment

ERW electric resistance welded

GIS geographic information system

GRI Gas Research Institute

GSR gas service representative

GTI Gas Technology Institute

HCA high consequence area

HV Vickers hardness number

INGAA Interstate Natural Gas Association of America

KSFO San Francisco International Airport

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ksi 1,000 pounds per square inch

LOF likelihood of failure

MAOP maximum allowable operating pressure

MOP maximum operating pressure

MP mile point

NPRM notice of proposed rulemaking

NTSB National Transportation Safety Board

PAPERS Public Awareness Program Effectiveness Research Survey

PG&E Pacific Gas and Electric Company

PHMSA Pipeline and Hazardous Materials Safety Administration

PLC programmable logic controller

psi pounds per square inch 

psig pounds per square inch, gauge

RCV remote control valve

RMP risk management procedure

RSPA Research and Special Programs Administration

SBFD San Bruno Fire Department

SCADA supervisory control and data acquisition

SMLS seamless

SMYS specified minimum yield strength

the Corps U.S. Army Corps of Engineers

UPS uninterruptible power supply

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Executive Summary

On September 9, 2010, about 6:11 p.m. Pacific daylight time, a 30-inch-diameter 

segment of an intrastate natural gas transmission pipeline known as Line 132, owned and 

operated by the Pacific Gas and Electric Company (PG&E), ruptured in a residential area in 

San Bruno, California. The rupture occurred at mile point 39.28 of Line 132, at the intersection 

of Earl Avenue and Glenview Drive. The rupture produced a crater about 72 feet long by 26 feet 

wide. The section of pipe that ruptured, which was about 28 feet long and weighed about 

3,000 pounds, was found 100 feet south of the crater. PG&E estimated that 47.6 million standard 

cubic feet of natural gas was released. The released natural gas ignited, resulting in a fire that 

destroyed 38 homes and damaged 70. Eight people were killed, many were injured, and many 

more were evacuated from the area.

Investigation Synopsis 

The National Transportation Safety Board’s investigation found that the rupture of 

Line 132 was caused by a fracture that originated in the partially welded longitudinal seam of 

one of six short pipe sections, which are known in the industry as “pups.” The fabrication of five 

of the pups in 1956 would not have met generally accepted industry quality control and welding 

standards then in effect, indicating that those standards were either overlooked or ignored. The 

weld defect in the failed pup would have been visible when it was installed. The investigation 

also determined that a sewer line installation in 2008 near the rupture did not damage the 

defective pipe. 

The rupture occurred at 6:11 p.m.; almost immediately, the escaping gas from the 

ruptured pipe ignited and created an inferno. The first 911 call was received within seconds. 

Officers from the San Bruno Police Department arrived on scene about 6:12 p.m. Firefighters at 

the San Bruno Fire Department heard and saw the explosion from their station, which was about 

300 yards from the rupture site. Firefighters were on scene about 6:13 p.m. More than 

900 emergency responders from the city of San Bruno and surrounding jurisdictions executed a 

coordinated emergency response, which included defensive operations, search and evacuation, 

and medical operations. Once the flow of natural gas was interrupted, firefighting operations 

continued for 2 days. Hence, the emergency response by the city of San Bruno was prompt and 

appropriate. 

However, PG&E took 95 minutes to stop the flow of gas and to isolate the rupture site—a 

response time that was excessively long and contributed to the extent and severity of property 

damage and increased the life-threatening risks to the residents and emergency responders. The 

National Transportation Safety Board found that PG&E lacks a detailed and comprehensive 

procedure for responding to large-scale emergencies such as a transmission pipeline break, 

including a defined command structure that clearly assigns a single point of leadership and 

allocates specific duties to supervisory control and data acquisition staff and other involved 

employees. PG&E’s supervisory control and data acquisition system limitations caused delays in 

pinpointing the location of the break. The use of either automatic shutoff valves or remote 

control valves would have reduced the amount of time taken to stop the flow of gas. 

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PG&E’s pipeline integrity management program, which should have ensured the safety 

of the system, was deficient and ineffective because it—

• Was based on incomplete and inaccurate pipeline information.

• Did not consider the design and materials contribution to the risk of a pipeline failure.

• Failed to consider the presence of previously identified welded seam cracks as part of 

its risk assessment.

• Resulted in the selection of an examination method that could not detect welded seam 

defects.

• Led to internal assessments of the program that were superficial and resulted in no 

improvements. 

Several deficiencies revealed by the National Transportation Safety Board investigation, 

such as PG&E’s poor quality control during the pipe installation and inadequate emergency 

response, were factors in the 2008 explosion of a PG&E gas pipeline in Rancho Cordova, 

California. (See Explosion, Release, and Ignition of Natural Gas, Rancho Cordova, California, 

December 24, 2008, Pipeline Accident Brief NTSB/PAB-10/01 [Washington, DC: National 

Transportation Safety Board, 2010].) This 2008 accident involved the inappropriate installation 

of a pipe that was not intended for operational use and did not meet applicable pipe 

specifications. PG&E’s response to that event was inadequate; PG&E initially dispatched an 

unqualified person to the emergency, causing an unnecessary delay in dispatching a properly 

trained and equipped technician. Some of these deficiencies were also factors in the 1981 PG&E 

gas pipeline leak in San Francisco, which involved inaccurate record-keeping, the dispatch of 

first responders who were not trained or equipped to close valves, and unacceptable delays in 

shutting down the pipeline. (See Pacific Gas & Electric Company Natural Gas Pipeline 

Puncture, San Francisco, California, August 25, 1981, Pipeline Accident Report 

NTSB/PAR-82/01 [Washington, DC: National Transportation Safety Board, 1982].) The 

National Transportation Safety Board concluded that PG&E’s multiple, recurring deficiencies 

are evidence of a systemic problem.

The investigation also determined that the California Public Utilities Commission, the 

pipeline safety regulator within the state of California, failed to detect the inadequacies in 

PG&E’s integrity management program and that the Pipeline and Hazardous Materials Safety 

Administration integrity management inspection protocols need improvement. Because the 

Pipeline and Hazardous Materials Safety Administration has not incorporated the use of effective

and meaningful metrics as part of its guidance for performance-based management pipeline 

safety programs, its oversight of state public utility commissions regulating gas transmission and 

hazardous liquid pipelines could be improved. Without effective and meaningful metrics in 

performance-based pipeline safety management programs, neither PG&E nor the California 

Public Utilities Commission was able to effectively evaluate or assess PG&E’s pipeline system.

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Probable Cause 

The National Transportation Safety Board determines that the probable cause of the 

accident was the Pacific Gas and Electric Company’s (PG&E) (1) inadequate quality assurance 

and quality control in 1956 during its Line 132 relocation project, which allowed the installation 

of a substandard and poorly welded pipe section with a visible seam weld flaw that, over time 

grew to a critical size, causing the pipeline to rupture during a pressure increase stemming from 

poorly planned electrical work at the Milpitas Terminal; and (2) inadequate pipeline integrity 

management program, which failed to detect and repair or remove the defective pipe section. 

Contributing to the accident were the California Public Utilities Commission’s (CPUC) 

and the U.S. Department of Transportation’s exemptions of existing pipelines from the 

regulatory requirement for pressure testing, which likely would have detected the installation 

defects. Also contributing to the accident was the CPUC’s failure to detect the inadequacies of 

PG&E’s pipeline integrity management program.

Contributing to the severity of the accident were the lack of either automatic shutoff 

valves or remote control valves on the line and PG&E’s flawed emergency response procedures 

and delay in isolating the rupture to stop the flow of gas. 

Recommendations 

The National Transportation Safety Board makes new recommendations to the 

U.S. Secretary of Transportation, the Pipeline and Hazardous Materials Safety Administration,

the governor of the state of California, the California Public Utilities Commission, the Pacific 

Gas and Electric Company, the American Gas Association, and the Interstate Natural Gas 

Association of America.

The National Transportation Safety Board previously issued recommendations to the 

Pipeline and Hazardous Materials Safety Administration, the California Public Utilities 

Commission, and the Pacific Gas and Electric Company as a result of this accident.

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1. Factual Information

1.1 Accident Narrative

On September 9, 2010, about 6:11 p.m. Pacific daylight time,

1 a 30-inch-diameter 

segment of an intrastate natural gas transmission2 pipeline known as Line 132, owned and 

operated by the Pacific Gas and Electric Company (PG&E), ruptured in a residential area in 

San Bruno, California. The rupture occurred at mile point (MP) 39.28 of Line 132,

3

The ruptured pipe segment was installed in 1956. According to PG&E records (which 

were later found to be incorrect), the ruptured segment was constructed from 30-inch-diameter,

seamless American Petroleum Institute (API) 5L

at the 

intersection of Earl Avenue and Glenview Drive. The rupture produced a crater about 72 feet 

long by 26 feet wide. (See figure 1.) The section of pipe that ruptured, which was about 28 feet 

long, and weighed about 3,000 pounds, was found 100 feet south of the crater. (See figure 2.) 

PG&E estimated that 47.6 million standard cubic feet of natural gas was released. The released 

natural gas ignited, resulting in a fire that destroyed 38 homes and damaged 70. (See figure 3.)

Eight people were killed, many were injured, and many more were evacuated from the area.

4

grade X425 steel pipe with a 0.375-inch wall

thickness. The maximum allowable operating pressure (MAOP6) for Line 132 was 400 pounds 

per square inch, gauge (psig). The PG&E specified maximum operating pressure (MOP7

 1 All times in this report are Pacific daylight time unless otherwise specified.

) was 

375 psig.

2 A transmission line is defined as a pipeline, other than a gathering line, that (1) transports gas from a gathering 

line or storage facility to a distribution center, storage facility, or large-volume customer that is not downstream 

from a distribution center; (2) operates at a hoop stress of 20 percent or more of specific minimum yield strength 

(SMYS); or (3) transports gas within a storage field.

3 MPs are measured along the length of the pipeline relative to the distance from the Milpitas Terminal, where 

Line 132 originates, which is designated as MP zero.

4 The API develops industry-based consensus standards that support oil and gas production and distribution. 

API 5L is a specification for line pipe.

5 This signifies that the pipe has a SMYS of 42,000 pounds per square inch (psi). Yield strength is a measure of 

the pipe’s material strength and indicates the stress level at which the material will exhibit permanent deformation. 

Although yield strength is expressed in psi, this value is not equivalent to a pipe’s internal pressure.

6 MAOP is defined by the Pipeline and Hazardous Materials Safety Administration (PHMSA) as the maximum 

pressure at which a pipeline or segment of a pipeline may be operated under Title 49 Code of Federal Regulations

(CFR) Part 192. (Part 192 contains the minimum Federal safety standards for the transportation of natural gas by 

pipeline.)

7 MOP is an operating limit defined by PG&E. As explained by PG&E, sometimes a line’s MOP equals the 

MAOP. But when a line is crosstied to (open to) a line with a lower MAOP, the higher rated line is limited by the 

MAOP of the lower rated line. In the case of Line 132, when it was open to Line 109 (which had a MAOP of 

375 psig), as it was at the time of the accident, the MOP of Line 132 was 375 psig. 

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Figure 1. Picture of crater and ruptured pipeline.

Figure 2. Picture of ejected pipe section.

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Figure 3. Aerial view of fire.

1.1.1 Preaccident Events

During the hours leading up to the accident, three PG&E employees and one contractor 

were working on an electrical distribution system as part of the replacement of the 

uninterruptible power supply (UPS8) at the Milpitas Terminal, where Line 132 originates. (See 

figure 4.) The electric work had been approved by a PG&E work clearance9 form, which was 

submitted to PG&E’s gas control center (referred to in this report as the SCADA10

 8 A UPS is an electrical apparatus that provides backup power.

center) on 

August 19, 2010, and approved on August 27, 2010. 

9 A work clearance is a procedure used by PG&E to notify the supervisory control and data acquisition 

(SCADA) center of work that may affect gas flow, gas quality, or SCADA monitoring. For more information about 

the work clearance process, see section 1.9.1.2, “Work Clearance Procedures.”

10 PG&E used a computer-based SCADA system to remotely monitor and control the movement of gas through 

its pipelines. SCADA operators located at the SCADA center in San Francisco monitor operating parameters such as 

flow rates, pressures, equipment status, control valve positions, and alarms indicating abnormal conditions. (For 

more information, see section 1.9.1, “SCADA System Operations.”)

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Figure 4. Overview of Line 132.

The work on September 9, 2010, was the continuation of a larger project to temporarily 

transfer electrical loads from an existing UPS distribution panel onto individual smaller UPS 

devices.

11

On the evening of September 9, 2010, one SCADA operator (operator D) became the 

primary point of contact for workers at the Milpitas Terminal, but at various times all five of the 

SCADA staff answered telephone calls and handled alarms relating to events at the 

Milpitas Terminal. The SCADA operators sat together in the SCADA center and communicated 

frequently throughout the evening about the work. (It should also be noted that the San Francisco 

SCADA operations were scheduled to move during the next shift to an alternate SCADA facility 

in Brentwood, California, as part of a regular exercise. Some of the SCADA operators scheduled 

to work the night shift, who had reported to the Brentwood location, were monitoring the lines 

and were communicating by telephone with the day shift SCADA staff in San Francisco. 

The intent of this operation was to complete the removal of all loads from the existing 

UPS distribution panel so it could be removed from service and replaced. Future work included 

replacing the UPS and transferring each load from the small, temporary UPSs back onto a new 

UPS.

 11 The smaller UPS devices serve a single component on a circuit.

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However, after the rupture of Line 132, the exercise at the Brentwood facility was cancelled, and 

the staff at Brentwood reported to the San Francisco facility.)

1.1.2 Events Leading Up to Rupture

At 2:46 p.m. (about 3.5 hours before the rupture), a gas control technician at the Milpitas 

Terminal (hereafter referred to as the Milpitas technician) spoke with SCADA operator A in 

San Francisco to initiate the work clearance for the planned UPS work. At 3:36 p.m., the 

Milpitas technician called the SCADA center and spoke with SCADA operator B to find out 

whether the valves on two of the incoming lines would close upon losing power. Operator B 

confirmed that they would fail closed. The Milpitas technician then informed operator B that he 

would lock the valves open.

Before performing the transfer of equipment that powered instrumentation and provided 

SCADA data to the SCADA center, the workers at the Milpitas Terminal called the supervisor of 

SCADA and controls to discuss the impacts of the work. He advised them to put the regulating 

control valves12

As the electrical work progressed, the Milpitas technician called the SCADA center to 

alert them each time work was about to begin that would affect SCADA data. In keeping with 

this practice, at 4:03 p.m., the Milpitas technician alerted SCADA operator C that the installation 

of one of the smaller UPSs was about to begin. The Milpitas technician stated that he was going 

to put the regulating valves in manual control at the regulating valve controllers and return them 

to automatic after the transfer was complete. During this portion of the electrical work, beginning 

at 4:18 p.m., the SCADA center lost SCADA data for pressures, flows, and valve positions at the 

Milpitas Terminal. SCADA operator B called the Milpitas Terminal at 4:32 p.m., asking “What’s 

going on?” in reference to the extended loss of SCADA data. During that phone call, the workers 

at the Milpitas Terminal were in the process of restoring power and SCADA data. At 4:38 p.m.,

the Milpitas technician contacted the SCADA center to verify the SCADA data had returned to 

normal. At the completion of this portion of the electrical work, the regulating valve controllers 

were returned to automatic control.

in manual control to prevent the valves from operating.

Following the transfer of critical loads from the UPS panel, workers at the 

Milpitas Terminal began to remove power from an unidentified breaker. During that work, the 

workers opened a circuit that resulted in a local control panel unexpectedly losing power. (See 

figure 5.) Rather than reenergizing the circuit, the workers pulled drawings and began 

investigating how to power the local control panel from an alternate source. One of the 

technicians stated in a postaccident interview that while measuring electrical currents with a 

clamp-on amp meter, the workers noticed some of the displays at the local control panel went 

blank. Subsequent troubleshooting showed this to be the result of erratic output voltages from 

two redundant 24-volt d.c. power supplies (power supplies A and B on figures 6a and 6b). These

 12 The regulating valves operate as the primary means of pressure control through the Milpitas Terminal. They 

are full port valves with electric actuators governed by controllers. Pressure sensors control the position of the 

valves from fully open to fully closed or in between to maintain a downstream pressure or be given a percent open 

by the gas system operator. 

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erratic voltages to pressure transmitters resulted in an erroneous low pressure signal to regulating 

valve controllers, causing them to command the regulating valves to a fully open position. (See 

figure 7.) Until then, the regulating valves on all incoming lines except Line 300B had been 

closed. When the valves opened fully, the monitor valves, whose purpose is to protect against 

accidental overpressure, became the only means of pressure control. The erratic voltages from 

the 24-volt power supplies also affected valve position sensors, generating erroneous signals to 

the SCADA center.

Figure 5. Picture of local control panel.

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Figure 6a. Normal electrical configuration at the Milpitas Terminal. 

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