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

At 5:52 p.m., the senior SCADA coordinator asked SCADA operator D to lower the 

upstream set points for gas supplying the Milpitas Terminal. When the Milpitas technician called 

operator D to report that the monitor valves were shut on Line 300B, operator D stated that his 

console was showing almost 500 psig on downstream headers

20

 20 A header is a common pipeline, typically of larger diameter, where two or more other pipelines combine 

through “T” connections. Headers are typically required when multiple redundant inlet sources are used to feed a 

single downstream location. 

3–7. He asked the 

Milpitas technician to place a pressure gauge on Line 132 to get a reading of the pressure leaving 

the Milpitas Terminal.

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At 6:02 p.m., operator D commented to a SCADA operator at the Brentwood facility, 

“we’ve got a major problem at Milpitas and we’ve over pressured the whole peninsula.” At 

6:04 p.m., the senior SCADA coordinator informed the supervisor at the Milpitas Terminal that 

the pressure on the incoming lines at the Milpitas Terminal had been lowered to 370 psig. At the 

same time, the Milpitas technician reported to SCADA operator C that he had manually read a 

pressure of 396 psig on outgoing Line 132. High-high pressure alarms continued to appear in the 

SCADA system until just after the rupture.

1.1.3 The Rupture

SCADA data indicate that the rupture occurred about 6:11 p.m., when the pressures on 

Line 132 upstream of Martin Station (7 miles downstream from the rupture site) rapidly 

decreased from a high of 386 psig. At the same time, a pressure of 386.4 psig was recorded at 

Half Moon Bay (located about 10 miles upstream of the rupture). By 6:15 p.m., Martin Station 

generated the first low pressure alarm for Line 132, followed 20 seconds later by another alarm

(150 psig). These low-pressure alarms occurred while SCADA operator D was on the phone with 

a SCADA operator at the Brentwood facility, who alerted him to the low pressures. By 

6:36 p.m., the Line 132 pressure at the Martin Station was 50 psig. The pressures in Lines 101 

and 109, which are interconnected to Line 132, also decreased but at a slower rate than Line 132. 

1.2 Emergency Response 

The first 911 call reporting an explosion was received about 6:11 p.m. Many subsequent 

911 calls were received from residents and police officers reporting a fire, a gas station 

explosion, and a possible airplane crash. San Bruno Police Department resources were

dispatched, and the first police unit arrived on scene about 6:12 p.m. The first San Bruno Fire 

Department (SBFD) firefighters to respond had heard the explosion and seen the fire from their 

station, which was about 300 yards from the accident site. They had reported the fire and were 

preparing to respond just as the initial dispatch (first alarm21

About the same time, 6:13 p.m., some residents began self evacuating from the accident 

area. Police officers then began securing the area and conducting evacuations south and north of 

the fire. At 6:16 p.m., police officers requested that California Highway Patrol troopers divert 

traffic from the scene. Troopers began closing highways in the immediate area.

) was issued. They were 

immediately en route and on scene about 6:13 p.m. (See figure 9.)

 21 A total of six alarms were requested as firefighters responded to various locations surrounding the accident 

area.

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Figure 9. Firefighters approaching accident scene.

At 6:18 p.m., an off-duty PG&E employee notified the PG&E dispatch center in 

Concord, California, of an explosion in the San Bruno area. Over the next few minutes, the 

dispatch center received additional similar reports.

About 6:20 p.m., the initial incident commander, a Millbrae Fire Department battalion 

chief, arrived on scene. When the SBFD chief later arrived on scene,22 he assumed incident 

command. A battalion chief from the North County Fire Authority was designated as the deputy 

incident commander.23 Fire operations were supervised by a Millbrae Fire Department division 

chief and were organized into area commands.

24

At 6:23 p.m., 5 minutes after the PG&E dispatch center received the first call reporting an 

explosion in the San Bruno area, a dispatcher sent a gas service representative (GSR) working in 

Battalion chiefs supervised each area. A 

representative from the county dispatch center responded to the accident area, and requests for 

additional response resources were relayed through this representative. 

 22 The SBFD chief’s arrival time was not recorded in any of the documentation provided to the National 

Transportation Safety Board (NTSB).

23 Forty-two local, county, state, and Federal fire departments assisted in the accident response.

24 Area command is a command organization established to oversee the management of large or multiple 

incidents.

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Daly City (about 8 miles from San Bruno) to confirm the report, as required by PG&E 

procedures. 25

About the same time, a PG&E supervisor (supervisor 1) saw the accident fire while 

driving home from work. He called the PG&E dispatch center, reported the fire, and then 

proceeded to the scene. 

By 6:24 p.m., firefighters responding to the south side of the accident area had reported to 

incident command that hydrants were dry. About the same time, firefighters responding to the 

north side discovered that the explosion had damaged a water line. To address this, firefighters 

established water supplies using 1,000–2,000 feet of large-diameter supply hose at two locations.

At 6:27 p.m., a PG&E dispatcher called the SCADA center and asked SCADA 

operator C if the SCADA center staff had observed a pressure drop “at a station in [the 

San Bruno] area.” The dispatcher stated that he had received reports of a flame shooting up in the 

air accompanied by a sound similar to a jet engine and that a PG&E supervisor and a GSR had 

been dispatched to the area. Operator C replied that the SCADA center had not received any 

calls about the incident. At 6:29 p.m., the senior SCADA coordinator informed a SCADA 

coordinator at the Brentwood facility that there had been a gas line break and further stated that 

there had been an overpressure event at the Milpitas Terminal earlier. Reports of a plane crash, a 

gas station explosion, or some combination of the two persisted throughout the initial hours of 

the emergency response. By 6:30 p.m., some staff at the SCADA center realized that there had 

been a rupture along Line 132 in the San Bruno area. However, they did not know the exact 

location of the rupture and continued to try to identify it.

About 6:30 p.m., the on-scene fire operations supervisor declared the incident a 

multi-casualty incident. Soon after, a medical group was established, and medical units were 

positioned north and south of the accident scene.

At 6:31 p.m., SCADA operator B reported to dispatch that there was “a major pressure 

drop at a station up in that area [near San Bruno].”

About 6:35 p.m., an off-duty PG&E gas measurement and control mechanic 

(mechanic 1), who was qualified to operate mainline valves, saw media reports about the fire. 

Suspecting a transmission line break, he notified the PG&E dispatch center, and proceeded to the 

PG&E Colma yard26

 25 PG&E procedures require the GSR to evaluate the danger to life and property, assess damage, and make or 

ensure that conditions are safe. The procedures also require field personnel to notify a field service supervisor, a 

dispatcher, a gas maintenance and construction supervisor, or an on-call gas supervisor. Nowhere does the procedure 

instruct field personnel, the dispatch center, or the SCADA center to contact emergency services through 911 or 

other means. The procedure does not discuss the involvement of city or emergency officials. Notifications that are 

outlined in the procedure focus on company personnel and supervisors only. On June 8, 2011, the NTSB issued 

safety recommendations relating to this PG&E procedure. For more information, see Section 1.12, “Previous NTSB 

Safety Recommendations.”

to obtain his service truck and the tools necessary to shut off mainline 

26 The Colma yard is a small PG&E facility about 4.5 miles from San Bruno, where equipment and vehicles are 

stored.

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valves. Mechanic 1 lived only a couple of miles from the accident site and the Colma yard. 

While en route to the Colma yard, mechanic 1 received a call from a supervisor (supervisor 2) 

directing him to report to the yard and to contact a second mechanic (mechanic 2) to do the 

same. Before mechanic 1 could place the call, mechanic 2 called him to check on his well being. 

Both mechanics proceeded to the Colma yard.

Meanwhile, another PG&E supervisor (supervisor 3), who lived about 4 miles from the 

rupture site, learned of the explosion and fire through media reports and notified the 

SCADA center. He then proceeded to the accident site.

About 6:40 p.m., firefighters requested two water tenders,27

Supervisor 1 was the first PG&E employee on scene. The GSR, who had been delayed in 

traffic, arrived shortly thereafter. Both were confirmed on scene at 6:41 p.m., with supervisor 3 

following soon after. However, none of these three PG&E first responders were qualified to 

operate mainline valves. Upon arrival, supervisor 3 and supervisor 1 informed firefighters of 

their presence as PG&E representatives on scene. 

which were used as water 

sources and assigned as needed to various locations around the fire. A California wildfire 

battalion chief was assigned as a liaison to oversee the water tenders. 

At 6:48 p.m., supervisor 1 called the PG&E dispatch center to request that gas and 

electric crews respond to the scene.

Mechanic 1 arrived at the Colma yard about 6:50 p.m., and mechanic 2 arrived soon 

after. They obtained a map showing the location of pipeline valves in the area and watched 

further news reports regarding the accident. Processing the visual information, mechanic 1 

recognized the rupture as occurring in Line 132 and called a supervisor (supervisor 4) to tell him 

he was going to isolate the rupture. Supervisor 4 authorized the action.

By 6:55 p.m., supervisor 3 had contacted another supervisor (supervisor 5) who activated 

the PG&E operations emergency center28

About 7:06 p.m., the two PG&E mechanics left the Colma yard, driving toward the first 

mainline valve (at MP 38.49) that they planned to close; they were joined en route by a 

supervisor (supervisor 6). The three arrived at the first valve location by 7:20 p.m. 

in San Carlos and declared supervisor 3 the deputy

incident commander.

 27 A water tender is a firefighting apparatus used to shuttle, store, and supply water.

28 The San Carlos operations emergency center command post is permanently equipped with computers, desks,

and communication equipment. PG&E’s emergency plans define the specific responsibilities of personnel staffing 

the center. The center directed field resources within the immediate San Bruno area. Later, a larger operations 

emergency center in the San Francisco headquarters was also activated because of the extent of the emergency. The 

San Francisco emergency operations center is a central location from which the emergency response activities of the 

local operating department are prioritized and coordinated.

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Meanwhile, the SCADA center and dispatch center staff were occupied with making 

outgoing calls to brief PG&E departments and officials of the incoming information, such as the 

rumors of an airplane crash and a gas station explosion. Between 6:50 and 7:00 p.m., SCADA 

operators D29 and B30 made comments indicating that there had been a break on Line 132, but 

SCADA operator C made comments indicating uncertainty as to the nature of the accident.31

At 7:22 p.m., at the direction of supervisor 3, supervisor 1 contacted the PG&E dispatch 

center to convey that although it was still unconfirmed, the incident was likely a reportable gas 

fire. Within minutes, the dispatch center relayed this information to the SCADA center; the 

SCADA center confirmed that Line 132 was involved.

During a phone call at 7:07 p.m., operator D responded to a dispatch employee who reported the 

rumor that there had been a plane crash by saying, “It’s easy to believe it’s a plane crash. We still 

have indication that it is a gas line break. We’re staying with that. If you talk to the fire 

department I would inform them of that.” There was no indication that the dispatch center passed 

this information to the fire department.

At 7:27 p.m., supervisor 6, who was with the two mechanics, requested that the 

SCADA center close two valves at the Martin Station. SCADA operator D remotely closed the 

valves downstream of the rupture by 7:29 p.m., which stopped the gas flow from north to south.

(See figure 10.)

By 7:30 p.m., the two mechanics had manually closed the mainline valve (at MP 38.49) 

south (upstream) of the rupture, stopping the gas flow at that location. By 7:42 p.m., 91 minutes 

after the rupture, the intensity of the fire had decreased such that firefighters could approach the 

rupture site and begin containment efforts. 

By 7:46 p.m., the two mechanics, with some assistance from supervisor 6, had manually 

closed two more valves downstream of the rupture (at MPs 40.05 and 40.05-2) at the 

Healy Station. Closing these valves isolated the ruptured section of pipe. 

About 7:57 p.m., a PG&E pipeline engineer informed the SCADA center staff that the 

rupture in Line 132 had occurred at MP 39.3332

 29 During a phone call beginning at 6:53 p.m., SCADA operator D said in a conversation with the on-site 

SCADA supervisor, “Yeah, absolutely we believe it’s a break on line 132.”

and explained that several mainline valves had 

been closed to isolate the break. He also told the staff that the downstream crosstie valves 

between Lines 109 and 132 had been opened to reestablish gas flow to the Martin Station. About 

the same time, the San Bruno Recreation Center, staffed by the American Red Cross, was opened 

as a shelter for evacuees.

30 During a phone call beginning at 6:55 p.m., SCADA operator B said to a dispatch employee, “Transmission 

line 132 is busted.”

31 During a phone call beginning at 6:55 p.m., SCADA operator C stated to supervisor 3, “I don’t think it is [a] 

transmission [line].”

32 PG&E has since clarified that the rupture occurred at MP 39.28.

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By 11:32 p.m., additional PG&E crews had manually closed two distribution line valves

and squeezed (that is, pinched with hand tools) three more distribution lines to stop the gas-fed 

house fires surrounding the pipeline rupture. 

Figure 10. Location of valve closures.

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Although the gas flow through the transmission line break and several local distribution 

lines had been stopped, the resulting fires continued. Firefighters declared 75 percent of all active 

fires to be contained about 4:24 a.m. on September 10. Fire operations continued to extinguish 

fires and monitor the accident area for hot spots until about 8:00 p.m. on September 11, when the 

SBFD transferred incident command to the San Bruno Police Department.

During the 50 hours following the accident, about 600 firefighting (including emergency 

medical service) personnel and 325 law enforcement personnel responded. Fire crews and police 

officers conducted evacuations and door-to-door searches of houses throughout the response. In 

total, about 300 houses were evacuated. Firefighting efforts included air and forestry operations. 

Firefighters, police officers, and members of mutual aid organizations also formed logistics, 

planning, communications, finance, and damage assessment groups to orchestrate response 

efforts and assess residential damage in the accident area. 

1.3 Injuries

As a result of the pipeline rupture and fire, 8 people were killed, 10 people sustained 

serious injuries, and 48 people sustained minor injuries. (See table 1.) For five of the fatalities, 

the cause of death was “generalized conflagration effects,” and for the remaining three, the cause 

of death was “undetermined.” Twenty-one people were transported to hospitals by ambulance, 

including three firefighters who were treated for smoke inhalation. Forty-five other people were 

transported to hospitals by private vehicle. 

Table 1. Injuries.

Injury Typea Number

Fatal 8

Serious 10

Minor 48

Total 66

a Title 49 CFR 830.2 defines fatal injury as any injury that results in death within 30 days of the accident and serious injury as an 

injury that (1) requires hospitalization for more than 48 hours, commencing within 7 days of the date the injury was received; 

(2) results in a fracture of any bone (except simple fractures of fingers, toes, or nose); (3) causes severe hemorrhages or nerve or 

tendon damage; (4) involves any internal organ; or (5) involves second- or third-degree burns, or any burn affecting more than 

5 percent of the body surface.

1.4 Damage

The rupture of Line 132 released an estimated 47.6 million standard cubic feet of natural 

gas, created a 72-foot-long by 26-foot-wide crater, and ejected a 28-foot piece of pipe weighing 

3,000 pounds, which came to rest about 100 feet away. The gas ignited and caused an explosion.

As previously noted in section 1.2, “Emergency Response,” the fire was declared about 

75 percent contained at 4:24 a.m. on September 10, 2010, about 10 hours and 13 minutes after 

the accident occurred. 

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The fire damage extended to a radius of about 600 feet from the pipeline blast center, 

mostly spreading in a northeast direction. (See figure 11.) The fire affected 108 houses—38 of 

which were destroyed, 17 of which received severe-to-moderate damage, and 53 of which 

received minor damage.33 (See figure 12.) In addition, 74 vehicles were damaged or destroyed. 

(See figure 13.) The burned area also included a park with woodlands and a playground. 

According to PG&E, the cost to repair the pipeline was about $13,500,000,

34 and the loss of 

natural gas accounted for $263,000.

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

 33 The city of San Bruno used the following damage categories to classify structural damage to houses at the 

accident site: (1) severe indicated that a house was not safe to occupy and most likely would need to be demolished 

or completely renovated prior to occupancy, (2) moderate indicated that a house had substantial damage and repairs 

would be necessary prior to occupancy, and (3) minor indicated that a house had the least amount of damage and 

could be legally occupied while repairs were being made.

34 PG&E has reported it will not be repairing Line 132 in the area of the accident.

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Figure 12. Picture of destroyed houses.

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

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1.5 Meteorological Information

Air temperature and moisture information was retrieved from the Automated Surface 

Observing System (ASOS) at San Francisco International Airport (KSFO), located about 3 miles 

to the east of the accident site at an elevation of 13 feet. Air temperature at the accident time 

(6:11 p.m.) was about 64° F and had decreased to 59° F by midnight. Dew point temperatures 

remained consistent at about 52° F throughout this period. The wind across the northern and 

central portion of the San Francisco peninsula was estimated to have been from the west with 

magnitudes from 15–25 knots (which equates to about 17–29 mph) from the accident time 

through about 10:00 p.m.35

1.6 Personnel Information

After 10:00 p.m., the wind magnitude decreased at the KSFO ASOS. 

At the NTSB’s request, a professional meteorologist familiar with the local terrain and 

micro-climates reviewed the small-scale wind flow for the accident neighborhood. This expert 

indicated that the wind in the accident area would have been from the northwest, aligned with 

Skyline Boulevard. Slightly northwest of the accident location, a branching of the northwesterly 

wind would have brought a weaker flow across the accident neighborhood from the 

west-northwest, with eddying also occurring. The expert estimated that wind speeds between 

6:00 and 9:00 p.m. would have been 15–20 mph.

1.6.1 Milpitas Technician and Other Workers at the Milpitas Terminal

The Milpitas technician had been on duty for about 12 hours 11 minutes when the 

accident occurred.36 He had been hired by PG&E on December 26, 1984. During his 

employment, the Milpitas technician had successfully completed 171 training courses. He had 

taken four courses specific to his position in the 17 months before the accident.

37

After the accident, PG&E had the four workers at the Milpitas Terminal provide 

specimens for toxicological testing, pursuant to 49 CFR 199.105 and 199.225.

The electrical 

contractor had been on duty for 4 hours 41 minutes at the time of the accident.

38

 35These wind magnitude estimates were based primarily on data retrieved from the KSFO ASOS and 

observations made by commercial aircraft near KSFO at altitudes close to the accident elevation. 

These 

36 Investigators collected detailed work/rest information for all of the employees at the Milpitas Terminal and 

the SCADA center who were on duty at the time of the accident. This information included awakening and to bed 

times, time awake, and time on duty on the day of the accident, as well as information from each employee about the 

quality of their overall rest, whether they had medical issues related to sleep, and whether they had received training 

about fatigue. For more information, see the Human Performance Group Chairman’s Factual Report and Addendum 

in the NTSB public docket for this accident.

37 Investigators collected information about training courses taken by each of the PG&E employees at the 

Milpitas Terminal and the SCADA center who were on duty at the time of the accident. (No training information 

was available for the contractor.) According to PG&E, available training courses specific to their duties included gas 

clearance process initial training, gas clearance process training, and refresher gas clearance process training. 

Training records indicated that each employee had successfully completed the gas clearance process initial training, 

six of the employees had also successfully completed the gas clearance process training, and one had successfully 

completed refresher gas clearance process training. For more information, see the Human Performance Group 

Chairman’s Factual Report in the NTSB public docket for this accident.

38 The California Public Utilities Commission (CPUC) requires PG&E to adhere to postaccident toxicological 

protocol consistent with PHMSA regulations.

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regulations require drug and alcohol testing for each employee whose performance either 

contributed to the accident or cannot be completely discounted as a contributing factor, and 

further state that the decision not to administer a test “shall be based on the operator’s 

determination, using the best available information at the time of the determination, that the 

covered employee’s performance could not have contributed to the accident.” (PHMSA has not 

issued any guidance regarding the type of analysis or justification that would be acceptable in 

reaching such a determination.) According to section 199.105, drug tests are to be conducted as 

soon as possible but no later than 32 hours after an accident. According to section 199.225, 

alcohol testing is to be conducted as soon as practicable after an accident, and if it is not done 

within 2 hours of an accident, the operator is required to prepare and maintain a record stating 

the reasons the test was not promptly administered. The regulation further states that if the test is 

not administered within 8 hours of the accident, the operator shall cease attempts to do so and 

state in the record the reasons for not administering the test.

PG&E notified its testing contractor at 12:30 a.m. on September 10 that drug and alcohol 

testing services were needed, and informed her that the 8-hour time frame for alcohol testing 

would likely be exceeded but instructed her to collect the specimens anyway. The contractor 

reported to NTSB investigators that she was never made aware of, nor did she inquire about, the 

time of the rupture. She indicated she was aware of the regulatory 8-hour time limit for alcohol 

testing. 

The Milpitas technician provided a urine specimen at 3:10 a.m. on September 10. The 

specimen was then tested for the following illegal drugs: cannabinoids, cocaine metabolites, 

opiates, amphetamines, and phencyclidine. The test results were negative. He also took a 

breathalyzer test to detect ethyl alcohol in his system. The test was administered at 3:36 a.m. on 

September 10.

Between 3:51 and 5:21 a.m. on September 10, specimens for drug and alcohol testing 

were also collected from two other PG&E employees and a contractor who had been on duty at 

the Milpitas Terminal when the accident occurred; the drug test results were negative.

No documentation was generated as to why alcohol testing was not promptly 

administered in accordance with 49 CFR 199.205. The CPUC indicated that it was investigating 

the untimely alcohol testing for possible enforcement action.

1.6.2 SCADA Operators

As previously noted, three operators were staffing the SCADA center at the time of the

pipeline rupture, and all three were involved in responding to the events surrounding the 

accident. SCADA operator D, who served as the primary point of contact with the 

Milpitas technician, had been on duty for about 12 hours 11 minutes when the accident occurred

and remained on duty for an additional 3 hours 20 minutes after the rupture. He had been hired 

by PG&E on June 18, 1979. Over the years, operator D had successfully completed 104 training 

courses. During the 17 months before the accident, he had taken three courses specific to his 

position.

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SCADA operator C had been on duty for about 12 hours 41 minutes when the accident 

occurred and remained on duty for an additional 3 hours 20 minutes after the rupture. He had 

been hired by PG&E on December 8, 1983. Operator C had successfully completed 76 training 

courses while employed with PG&E. During the 18 months before the accident, he had taken 

three courses specific to his position. 

SCADA operator B had been on duty for about 13 hours 6 minutes when the accident 

occurred and remained on duty for an additional 3 hours 50 minutes after the rupture. He had 

been hired by PG&E on September 17, 1974. Throughout his career, he had successfully 

completed 86 training courses. He had taken three courses specific to his position in the 

17 months before the accident. 

PG&E did not conduct drug or alcohol testing for any of the employees at the 

SCADA center. PG&E indicated that the SCADA staff were not identified for testing because 

they were “deemed to be monitoring and responding to the rupture, not contributing to the 

rupture event.”

1.7 Pipeline Information

1.7.1 Line 132

Line 132 originates at the Milpitas Terminal and extends north about 46 miles to the 

Martin Station.

39

 39 Line 132 continues north beyond the Martin Station for a short distance as a distribution line.

(See figure 14.) Line 132 is one of three gas transmission lines in the PG&E 

peninsula system. The other two are Lines 101 and 109. In all three lines, gas flow is typically 

from south to north. The peninsula system includes six crossties that connect the three 

transmission lines and allow gas to flow between them. (Four of those crossties are shown on 

figure 14; the two not shown connect Lines 132 and 109 at MPs 29.06 and 31.93.)

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

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Line 132 was originally constructed in phases, with construction projects in 1944 and 

1948. According to the PG&E geographic information system (GIS),40

In response to a request for construction records for the 1948 portion of the Line 132 

project, PG&E provided more than 18,000 pages of records, including material procurement 

orders from the Consolidated Western Steel Corporation (Consolidated Western) Maywood, 

California, plant, accounting records, specifications, foreman journal entries, and radiography 

receipts. The records indicated that 10 percent of the girth welds

Line 132 is made up of 

24-, 30-, 34-, and 36-inch-diameter segments of various steel grades with various longitudinal 

seam weld types, such as double submerged arc welded (DSAW), electric resistance welded 

(ERW), and seamless (SMLS).

41

The foreman’s log from the 1948 construction project noted several instances of 

construction damage, including dents and dent repairs. 

were radiographed (that is,

x-rayed) at the construction site and inspected according to a set of standards agreed upon by 

engineers from PG&E and the construction contractor. Radiographs of the girth welds also 

captured a small portion of the longitudinal welds from each of the two pipe segments joined by 

the girth weld being radiographed. Records from the 1948 project included logs for 

209 radiographs, including 19 rejected welds, 4 of which were reexamined and determined to be 

acceptable. Those four were all longitudinal welds. Of the remaining 15 rejected welds, 5 were 

longitudinal welds and 10 were girth welds. An additional 14 girth welds were classified as 

“borderline.”

After the 1948 installation, the 20- and 24-inch segments of Line 132 were tested for 

leaks in accordance with the construction contract by introducing air at 100 psig and using a soap 

and water solution on girth welds. According to construction records, as a final check before 

introducing gas, the 20- and 24-inch segments were pressured to 100 psig with air and held for 

48 hours. Gas was introduced into the 30-inch portion of the line upon completion, and the line 

was checked “for leaks and breaks.”

1.7.2 1956 Relocation Project (Segment 180)

In 1956, PG&E relocated 1,851 feet of Line 132 that had originally been installed in 

1948. The relocation was necessary because the existing elevation of Line 132 was incompatible 

with land grading that had been done in connection with residential housing being built at that 

location. This relocation, which included the installation of the pipe at the accident location, 

started north of Claremont Drive and extended south to San Bruno Avenue, and rerouted

Line 132 from the east side to the west side of Glenview Drive. (See figure 15.) The relocation 

work was not contracted out, but rather was performed by PG&E construction crews.

Construction documentation provided to the NTSB consisted of about 300 pages of journal 

vouchers, material transfers, paving receipts, and various other cost accounting sheets. PG&E did 

 40 The GIS is a database of pipeline attributes populated by PG&E.

41 Girth welds, which are typically done at the time of installation in the field, join adjacent pipe pieces and 

extend around the circumference of the pipe. 

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not provide any design/material or construction specifications, inspection records, as-built 

drawings, or radiography reports. A reference to two cases of bar soap “for testing” was the only 

indication that any type of on-site leak testing of the girth welds may have been performed.

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

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In 1961, PG&E completed a second relocation project on a portion of Line 132 

immediately to the south of the 1956 relocation. As a result, 1,742 feet of the original 1,851 feet 

of pipe from the 1956 relocation project, including the rupture location, remained in operation. In 

PG&E’s records, this segment is known as Segment 180. 

At the time of the accident, Segment 180 was documented in the PG&E GIS as 

30-inch-diameter seamless steel pipe API 5L X42 with a wall thickness of 0.375 inch, installed 

in 1956. The manufacturer is listed as “NA,” indicating the information was unknown or 

unavailable. This portion of the GIS database was populated in 1998 using data from a pipeline 

survey sheet created in 1977. PG&E discovered during the investigation of this accident that the

material specification information for Segment 180 on the 1977 pipeline survey sheet had been 

obtained from accounting records rather than engineering records. Specifically, the source of the

information was a 1956 journal voucher used to allocate material expenses from one construction 

job to another, which contained an erroneous material description. 

After the accident, NTSB investigators discovered that Segment 180 was not 

X42 seamless pipe, as stated in the GIS database, and that other documents relating to the 

1956 project had correctly indicated that the pipe intended for use in that project had a DSAW

longitudinal seam. The investigation revealed that seamless pipe was not, and still is not,

available in diameters larger than 26 inches. The PG&E director of integrity management and 

technical support acknowledged in postaccident interviews that during the time when the pipe for 

Segment 180 was purchased, all 30-inch pipe purchased by PG&E would have been DSAW, not 

seamless. Investigators also discovered that the material code listed on the journal voucher 

corresponded to X52 pipe, not X42.

The investigation also revealed that the pipeline at the rupture location was made up of 

six short pipe segments, known as pups, which were welded together circumferentially. None of 

the pups were X52 pipe. Each pup ranged from 3.5–4.7 feet long. The NTSB Materials 

Laboratory determined through tensile and chemical composition testing that the material 

properties in some of the pups did not meet PG&E 1948 material specifications or industry 

pipeline material specifications for this time period. The GIS database did not reflect the 

presence of these pups, although it is intended to record each change in material properties as a 

separate segment. Further, the investigation revealed that several of the pups had partially 

welded longitudinal seams that left part of the seam unwelded and that several girth welds 

joining the pups contained multiple weld defects. Examination revealed that the longer pipe 

pieces (joints) on either side of the sequence of pups were standard X52 DSAW pipe. (For more 

information about the pups, see section 1.8, “Examination of Accident Pipe.”)

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As noted earlier in this section, PG&E could not produce any design/material or 

construction specifications for the 1956 relocation project. PG&E stated its belief that the project 

followed the standards in the American Society of Mechanical Engineers (ASME)-sponsored 

code B31.1.8, 1955 edition, Gas Transmission and Distribution Piping Systems.

42

According to PG&E, the pipe used was left over from previous purchases of pipe for 

other construction projects. According to PG&E, between 1947 and 1957, it purchased a total of 

320,065 feet of 30-inch pipe from three suppliers. Based on its records search and the 

characteristics of the accident pipe, including the numbers painted on the inside of the DSAW 

long joint south of the pups, PG&E indicated its belief that the pipe at the location of the rupture 

was most likely manufactured by Consolidated Western in 1948, 1949, or 1953 and was 

originally purchased for Line 153, Line 131, or the 1948 Line 132 project. PG&E stated that 

Consolidated Western manufactured the pipe for these three projects at its Maywood, California,

plant until May 1949, and afterwards at its South San Francisco plant. NTSB investigators 

examined the records and determined that the pipe used for the 1956 project was assembled from 

multiple material procurement orders. 

In 1955, 

PG&E’s then-superintendent of gas transmission and distribution was an active member of the 

ASME B31.1.8, 1955 edition, code committee.

The PG&E 1948 specification for 30-inch pipe, the most recently applicable specification 

at the time of the 1956 relocation project, called for steel pipe with longitudinal seams joined by 

electric fusion welding (now referred to as submerged arc welding43

each length of pipe...including jointers, shall be tested to a hydro-static pressure 

which will produce a stress of 90% of the specified minimum transverse yield 

strength [1170 psi in the case of 30-inch pipe with a wall thickness of 0.375 inch], 

which pressure shall be maintained for not less than ten seconds. ...While under 

pressure, the pipe length shall be struck a blow with a two-pound hammer, or its 

equivalent, near both ends of the weld.

). A PG&E document 

prepared in 1962, titled “History of Pipe Purchases,” states that, beginning in 1948, all purchased 

pipe with diameters of 20–36 inches would have been DSAW pipe. For pipe with 

0.375-inch-thick walls, it specified that wall thickness could not be less than 90 percent of the 

specified thickness and that any defect reducing the wall thickness to less than this amount 

would be considered injurious. It also specified a minimum yield strength of 52,000 psi. 

Regarding hydrostatic pressure tests at the time of manufacture (that is, at the pipe mill), the 

specification stated that—

The PG&E specification further provided that 95 percent of the finished pipe sections 

were to be between 30 feet 6 inches long and 31 feet 4 inches long. Consistent with 

 42 All versions of the ASME-sponsored codes for pressure piping are referred to in this report as ASME codes, 

even though several other organizations have also been associated with their development over time. The ASME 

code for pressure piping was originally developed in cooperation with the American Engineering Standards 

committee, which later changed its name to the American Standards Association, and then to the American National 

Standards Institute, Inc. 

43 Submerged arc welding is a form of arc welding where the filler wire and the pipe seam are submerged in a 

bed of pelletized flux. The flux protects the weld from impurities while it is in its molten state. 

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API standards at that time, it stated that no more than 5 percent of the order could consist of 

jointers, defined in the specification as two (or more)

44

In July 1949, Moody Engineering Company submitted a report to PG&E on the 

supervision and inspection of the manufacture of 100,000 feet (3,222 pieces) of 30-inch-diameter 

pipe by Consolidated Western’s Maywood, California, manufacturing plant. The report 

explained the manufacturing process, the chemical and physical properties of the steel, and the 

hydrostatic pressure test procedure used at the factory. According to the report, based on 

inspections of each piece of pipe, 244 pieces were repaired to meet PG&E specifications, and 

19 pieces were permanently rejected. Moody Engineering Company concluded that the pieces 

that had been accepted met PG&E specifications and were shipped in March and April 1949.

pieces of pipe joined by welding, and that 

a jointer could not contain pipe lengths measuring less than 5 feet. At the NTSB’s investigative 

hearing, the PG&E director of integrity management and technical support testified that he 

believed the accident segment of pipe was a jointer manufactured at a mill. 

1.7.3 Multiyear Replacement Project and Seismic Risk

According to the PG&E GIS, in 1995, PG&E replaced several sections of Line 132, 

including segments that ended about 565 feet to the south and about 610 feet to the north of 

Segment 180. These replacements were part of a multiyear replacement project on the peninsula 

lines to address seismic hazards. Some segments of Lines 109 and 132 crossed the San Andreas 

Fault and were therefore rerouted to reduce seismic risk. Segment 180 does not cross the fault,

and a 1992 report prepared by the PG&E geosciences department in connection with the 

replacement project indicated that Segment 180 had a low-to-moderate seismic risk. The 

subsequent risk assessments of Segment 180 assigned a score of 0 for any “ground movement” 

threat. (For more information on threat scores and risk assessment, see section 1.9.4, “PG&E 

Risk Management/Integrity Management Program.”) A low seismic risk for the accident area 

was also indicated by a February 2011 report prepared for PG&E under contract by TRE Canada, 

a company that specializes in measuring ground deformation using satellite imagery. 

TRE Canada analyzed the Earl Avenue and Glenview Drive area from May 1992–August 2010 

and found that the accident area did not experience any significant vertical movement during that 

time.

According to a PG&E public information fact sheet, the purpose of the multiyear project, 

which began in 1985, was “to maintain safe and reliable gas service to our customers,” and it 

would eventually “replace all aging natural gas pipelines in the system over a 25-year period.” In 

addition to seismic hazard, other factors considered in setting replacement priorities for the 

project were age, construction factors, and condition of the pipe.

 44 PG&E provided multiple documents containing the specification. In one document, jointers are defined as 

“two pieces joined by welding,” and in another as “two or more pieces joined by welding.” 

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1.7.4 Underground Environment at Accident Location

At the time of the accident, Line 132 was buried underground along the west side of 

Glenview Drive.45 Other underground utilities at the accident site included a 6-inch-diameter 

water line, which crossed about 2.5 feet above Line 132 at the location of the rupture and was 

destroyed, resulting in the lack of functional fire hydrants near the accident scene. A 

10-inch-diameter sanitary sewer line crossed below Line 132 about 108 inches south of pup 1. 

(The sewer line is discussed further below.) In addition, a 4-inch-diameter gas distribution line 

ran parallel to Line 132, about 6 feet 9 inches to the west. (See figure 16.) Farther below the 

buried utilities, at a depth of about 9 feet, was a drainage system with a catch basin running from 

west to east, which emptied into a canyon just east of the accident location. 

Figure 16. Sketch of underground utilities environment.

1.7.4.1 2008 Sewer Replacement

In June 2008, the city of San Bruno issued a change order to an existing contract to 

upgrade the sanitary sewer main along Earl Avenue to Glenview Drive. The change order 

specified that the contractor replace the existing 6-inch vitrified clay sewer pipe with a 

10-inch-diameter polyethylene pipe by pneumatic pipe bursting, which is a widely used method 

of replacing buried pipe without digging an open trench. Two pits are required to install the new 

 45 As a result of the rupture, this portion of Line 132 is no longer in service.

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pipe: an entry pit (normally a long slender trench to allow the pipe to bend as it is introduced into 

the ground) and an exit pit (normally a square pit at an existing manhole to allow for the cable, 

pulley block, and bursting head removal). The bursting head, a conical pneumatic expanding 

device, is introduced through the entry pit. It travels through the existing pipe, breaking it into 

pieces and radially expanding the existing hole. The new pipe, attached to the back of the 

bursting head, is simultaneously pulled into place. The bursting head is pulled by a cable that 

runs through the existing sewer pipe to the exit pit, through a pulley block, and up to a winch 

located above the exit pit at street level. 

The existing sewer pipe ran underneath Line 132 at the intersection of Earl Avenue and 

Glenview Drive, requiring an excavation of the sewer pipe on either side of Line 132. The 

contractor dug a potholing46

Prior to the excavation, the contractor had contacted the local one-call service company

trench that extended about 4 feet or more to the west and 3 feet to 

the east of Line 132. Further, according to the contractor, in the area where the sewer pipe 

crossed under Line 132, the old sewer pipe was broken up and removed by hand before the 

pipe-bursting operation began. The pneumatic expanding device was turned off as it passed 

under the area where the sewer pipe crossed under Line 132.

47

The exit pit was located at an existing manhole on Glenview Drive approximately 8 feet 

from the east side of Line 132. A 10-ton constant tension winch was located at the west wall of 

the pit.

and filed the required notices.

48

The pipe bursting began at the entry pit 290 feet to the west on Earl Avenue. A video of 

the project recorded the sound of the pneumatic bursting and showed the movement of the 

replacement pipe at the exit pit and the movement of the cable at the winch. Based on the 

recording, the pneumatic bursting rate was 214 strokes per minute. Based on the video, the 

replacement pipe pull rate ranged from 0.1–0.2 inches per second. According to the contractor, 

the maximum load on the winch was 14,000 pounds and the diameter of the cable was 

0.562 inch. As the bursting head approached the potholing trench, the pneumatic device was 

turned off. From there, the replacement sewer pipe was pulled through the potholing trench, 

underneath Line 132, and up to the exit pit. (See figure 17.)

The cable traveled down from the winch, into the exit pit, and over a pulley that was 

braced near the bottom of the pit against three overlapping sheet pilings. The outer two pilings 

spanned the full height of the pit and were driven into the floor of the pit at the west wall. The 

shortest distance from the center of the sheet pilings to the sidewall of Line 132 was estimated to 

be 7.7 feet. As the cable left the exit pit, it passed under Line 132, through the potholing trench, 

and continued along the existing sewer pipe to the entry pit.

 46 Potholing refers to holes used when excavating the ground near a utility service to visually locate the utility. 

Small holes are dug on either side of a pipe with a backhoe until the location of the utility can be visually confirmed. 

47 A one-call, or 811, service is a required notification system used to ensure the identification and marking of 

buried pipelines before excavation.

48 Constant tension indicates that the force exerted by the winch on the cable can be set to a constant value, 

selected by the operator, that otherwise does not vary during the bursting process.

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Figure 17. Diagram of excavations relative to Segment 180. 

According to postaccident interviews, a PG&E gas mechanic was on site while part of the

potholing trench was hand dug and after the polyethylene sewer pipeline had been pulled into the 

exit pit. The gas mechanic measured the vertical clearance between the bottom of Line 132 and 

the top of the new sewer pipeline, and determined that there was about 9 inches of clearance 

between the two. He also inspected the gas pipeline for damage and was satisfied with the work; 

he did not mention any problems or express any concern to the contractor foreman. The 

contractor proceeded to backfill the trench. The backfilling was neither witnessed nor inspected 

by the PG&E gas mechanic.

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1.7.4.2 Guidelines for Pipe Bursting 

Investigators reviewed studies that quantify safe distances for pipe bursting adjacent to 

utilities. According to one study,49 there is a 95 percent probability that ground vibrations will be 

within safe levels for buried utilities at a distance of 7.5 feet or more from the bursting head, 

unless the buried utility is in poor structural condition. Nearby utilities and buried structures 

closer than 7.5 feet may require a small excavation (that is, potholing) in the bursting path to 

provide shielding from the vibration. Another report50

1.7.4.3 Pipe Bursting Study

concluded that the bursting head should 

not pass closer than 2.5 feet from buried pipes and 8 feet from sensitive surface structures. That 

report states that the problems related to nearby utilities are often relieved by localized 

excavations; to avoid damage, the general rule is that nearby utilities should be excavated 

whenever the vertical and horizontal separation is less than twice the replacement pipe diameter 

between the new pipe and existing utilities.

Investigators used information from a land survey of the accident site, the above 

referenced studies on pipe bursting ground vibrations, a video of the Earl Avenue sewer 

replacement project, and the contractor’s testimony to calculate the forces on Line 132 caused by 

the pipe bursting process. Investigators considered the effect of ground vibrations from the 

bursting head, constant loads from the winch at the exit pit, and vibratory loads from the winch 

at the exit pit. The calculations indicated that ground vibrations from the bursting head could 

have deformed pup 1 (where the rupture initiated) out-of-round by up to 0.004 inch. The effect of 

the deformation on the stress state of the pup 1 seam weld defect was less than a 6-psi change in 

internal gas pressure. The calculated external soil pressure on the side of pup 1 (approximately 

10 feet from the winch brace), due to the 14,000-pound load on the sidewall of the exit pit, was 

0.1 psi. This soil pressure had an effect on the stress state of the pup 1 seam weld defect 

equivalent to a 2.5-psi increase in internal gas pressure. The calculated variation in external soil 

pressure due to vibratory loads on the sidewall of the pit was less than 0.01 psi. The internal gas 

pressure on the day of the sewer replacement project was approximately 365 psig. In 2008, the 

gas pressure in Line 132 varied daily by up to 110 psi.

1.7.5 Pipeline MAOP

Prior to 1961, there were no regulations in the state of California governing natural gas 

pipeline safety. There was, however, a voluntary national consensus standard in ASME B31.1.8, 

1955 edition, which called for hydrostatic pressure testing of newly constructed pipelines 

at 1.1–1.4 times the intended MAOP, depending on the class location. PG&E elected not to 

hydrostatically test Segment 180 of Line 132, and it is unknown if PG&E followed the other 

guidelines of the ASME standard.

 49 A. Atalah, “The Ground Vibration Associated With Pipe Bursting in Rock Conditions,” paper presented at 

North American Society for Trenchless Technology, NO-DIG 2004, New Orleans, Louisiana, March 22-24, 2004.

50 J. Simicevic and R.L. Sterling, Guidelines for Pipe Bursting, TTC Technical Report #2001.02 (prepared by 

Trenchless Technology Center for U.S. Army Corps of Engineers, Engineering Research and Development Center, 

2001).

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In 1961, the CPUC began regulating natural gas pipeline safety in California under 

General Order 112, State of California Rules Governing Design, Construction, Testing, 

Operation, and Maintenance of Gas Gathering, Transmission, and Distribution Piping Systems,

which was based on the ASME B31.1.8, 1958 edition. General Order 112 required hydrostatic 

pressure testing of newly constructed pipelines in class 3 areas at 1.5 times the intended MAOP, 

however it was not applied retroactively to existing installations such as Line 132. Therefore, 

PG&E was not required to pressure test Line 132 to comply with General Order 112.

Federal regulations issued in 1970 include a requirement in 49 CFR 192.505 that any

segment of newly constructed gas transmission pipeline intended to operate at a hoop stress51

1.7.5.1 “Grandfather Clause”

of 

30 percent or more of its SMYS undergo a hydrostatic pressure test for a minimum of 8 hours to 

substantiate its MAOP. In certain class 1 or 2 locations, the test pressure must be at least 

125 percent of the MAOP; in class 3 and 4 locations, the required pressure is 150 percent of 

MAOP. The MAOP for a newly constructed pipeline segment is derived from the pressure used 

during this hydrostatic testing.

For pipelines constructed before 1970 that were not required to be hydrostatically tested, 

49 CFR 192.619(a) (3), known as the “grandfather clause,” allows the MAOP to be based on 

“the highest actual operating pressure to which the segment was subjected during the 5 years 

preceding ... July 1, 1970.” In contrast to MAOP based on hydrostatic pressure testing, the 

grandfather clause does not specify a minimum amount of time that the historical pressure must 

have been held to be used as the basis for the MAOP.

As originally proposed, 49 CFR 192.619 did not include a grandfather clause but rather 

specified that the MAOP be set at the lowest of several alternatives, including (1) the design 

pressure of the weakest element in the pipeline system or (2) a percentage, based on the class 

location, of the pressure to which the pipeline was tested after construction. However, the 

Federal Power Commission (the predecessor of the Federal Energy Regulatory Commission) 

submitted comments on the proposed rule, pointing out that the proposed MAOP limits were 

similar to those in the ASME-sponsored B31.8, 1968 edition, Gas Transmission and Distribution 

Piping Systems. The Federal Power Commission stated—

The proposed regulation does not recognize that the B31.8 Code did not 

establish these minimum test levels until 1952. Prior to that time, between 1935 

and 1951, the predecessor Code, B31, required only that a pipeline be tested to a 

pressure 50 [psig] in excess of the proposed maximum operating pressure.

There are thousands of miles of jurisdictional interstate pipelines installed 

prior to 1952, in compliance with the then existing codes, which could not 

continue to operate at their present pressure levels and be in compliance with [the]

proposed section [].

 51 A hoop stress is a circumferential stress in thin-walled cylinders (for example, the internal diameter is greater 

than 40 times the wall thickness) and is assumed to be approximately uniform through the thickness of the wall.

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The [Federal Power] Commission has reviewed the operating record of the 

interstate pipeline companies and has found no evidence that would indicate a 

material increase in safety would result from requiring wholesale reductions in the 

pressure of existing pipelines which have been proven capable of withstanding 

present operating pressure through actual operation. 

The preamble to the final rule establishing Part 192 stated—

[i]n view of the statements made by the Federal Power Commission, and the fact 

that [the U.S. Department of Transportation (DOT)] does not now have enough 

information to determine that existing operating pressures are unsafe, a 

‘grandfather’ clause has been included in the final rule to permit continued 

operation of pipelines at the highest pressure to which the pipeline had been 

subjected during the 5 years preceding July 1, 1970.52

In 1987, the NTSB recommended elimination of the grandfather clause in 

Safety Recommendation P-87-9. In 1989, the Research and Special Programs Administration

(RSPA), the predecessor agency of PHMSA, issued an advance notice of proposed rulemaking 

(ANPRM) inviting public comment on whether the grandfather clause should be eliminated.53

PHMSA statistics indicate that 61 percent of onshore gas transmission pipelines (about 

180,000 miles) were installed prior to 1970. PHMSA does not keep track of how many of these 

pipelines have MAOPs established under the grandfather clause. 

The ANPRM noted that the grandfather clause allowed certain pipelines to operate at hoop stress 

levels above 72 percent of SMYS, whereas nongrandfathered pipes were limited to 72 percent of 

SMYS. The ANPRM also noted that the NTSB had recommended elimination of the grandfather 

clause. Based on public comments received on the 1989 ANPRM, RSPA decided not to 

eliminate the grandfather clause. (For more information on Safety Recommendation P-87-9 and 

the ANPRM, see section 1.12, “Previous NTSB Safety Recommendations.”)

1.7.5.2 MAOP for Line 132

The MAOP for Line 132 was established as 400 psig pursuant to the grandfather clause. 

According to PG&E logs from the Milpitas Terminal, the highest operating pressure on Line 132 

during the applicable 5-year period was 400 psig on October 16, 1968. 

The MOP set by PG&E for Line 132 was 375 psig. According to the manager of the 

PG&E integrity management program, PG&E considers the MOP to be the maximum pressure at 

which a pipeline system, as distinguished from a pipeline segment, can operate. She explained 

that the MOP of a pipeline system is governed by the lowest MAOP of any interconnected lines. 

Thus, when crossties connecting Line 132 (MAOP of 400 psig) and Line 109 (MAOP of 

375 psig) are open, the MOP of Line 132 is the MAOP of Line 109—that is, 375 psig. 

 52 Federal Register, vol. 35, no. 161 (August 19, 1970), p. 13248.

53 Federal Register, vol. 54, no. 236 (December 11, 1989), p. 50780.

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1.7.5.3 Periodic Pressure Increases to MAOP

Title 49 CFR 192.917(e) addresses required actions for particular threats. It is one of the 

integrity management program rules that became effective in 2004 54

(3) Manufacturing and construction defects. If an operator identifies the 

threat of manufacturing and construction defects (including seam defects) in the 

covered[

and states, in part:

55] segment, an operator must analyze the covered segment to determine 

the risk of failure from these defects. The analysis must consider the results of 

prior assessments on the covered segment. An operator may consider 

manufacturing and construction related defects to be stable defects if the 

operating pressure on the covered segment has not increased over the maximum 

operating pressure experienced during the five years preceding identification of 

the high consequence area. If any of the following changes occur in the covered 

segment, an operator must prioritize the covered segment as a high risk segment 

for the baseline assessment or a subsequent reassessment.

(i) Operating pressure increases above the maximum operating pressure 

experienced during the preceding five years;

(ii) MAOP increases; or

(iii) The stresses leading to cyclic fatigue increase.

(4) ERW pipe. If a covered pipeline segment contains low frequency 

electric resistance welded pipe (ERW),[56] lap welded pipe or other pipe that 

satisfies the conditions specified in ASME B31.8S,

[57

PG&E had a practice of raising the operating pressure to MAOP once every 5 years on 

several of its pipelines, including Line 132 and the other peninsula lines (Lines 101 and 109), as 

a strategy to continue classifying any manufacturing and construction defects on those lines as 

“stable,” meaning that they were not anticipated to grow in service.

] Appendices A4.3 and 

A4.4, and any covered or noncovered segment in the pipeline system with such 

pipe has experienced seam failure, or operating pressure on the covered segment 

has increased over the maximum operating pressure experienced during the 

preceding five years, an operator must select an assessment technology or 

technologies with a proven application capable of assessing seam integrity and 

seam corrosion anomalies. The operator must prioritize the covered segment as a 

high risk segment for the baseline assessment or a subsequent reassessment.

 54 For more information about integrity management programs, see Section 1.10.2, “Federal Oversight by 

PHMSA.”

55 A covered segment is defined in 49 CFR 192.903 as a segment of a gas transmission pipeline located in a 

high consequence area (HCA).

56 Line 132 includes several ERW segments. 

57 ASME-sponsored code B31.8S, 2004 edition, Managing System Integrity of Gas Pipelines: ASME Code for 

Pressure Piping, B31 Supplement to ASME B31.8.

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According to PG&E, the pressure on Line 132 was raised to 400 psig at the 

Milpitas Terminal in December 2003 and December 2008 for about 2 hours each time. During 

the pressure increase, the downstream pressures at the Martin Station in 2003 and 2008 were 

383 psig and 382 psig, respectively, due to the normal pressure gradient. PG&E acknowledged in 

response to inquiries from NTSB investigators that the pressure needed to serve customers is not 

usually the MAOP. However, PG&E went on to explain that—

under certain circumstances where the operating pressure is raised above the 

maximum pressure experienced during the preceding [5] years, PHMSA 

regulations ... require the operator to schedule a priority assessment capable of 

assessing seam integrity. In these circumstances, ASME B31.8S calls for a 

hydrostatic pressure test, which would take a line out of service for a period of at 

least a week. To avoid this and any potential customer curtailments that may 

result, PG&E has operated, within the applicable 5-year period, some of its 

pipelines that would be difficult to take out of service at the maximum pressure 

experienced during the preceding 5-year period in order to meet peak demand and 

preserve the line’s operational flexibility. 

The regulatory history of 49 CFR 192.917(e)(3) indicates that the rule as originally 

proposed called for a one-time pressure test to address manufacturing and construction defects.58

However, the final rule59

[PHMSA] has been convinced by the public comments, including discussions at 

the public meetings, that it is not necessary to require a once-in-a-lifetime 

pressure test to address the threat of material and construction defects. Historical 

safe operation, which in many cases involves several decades, provides 

confidence that latent defects will not result in pipeline failure as long as 

operating conditions remain unchanged. The final rule requires that an assessment 

be performed if operating pressure is increased above the historic level or if 

operating conditions change in a manner that would promote cyclic fatigue.

did not include this requirement. The preamble to the final rule 

explained: 

At the NTSB investigative hearing, the PHMSA deputy associate administrator for field 

operations testified that, “it was not the intent when the regulation was written that it would 

warrant the raising of pressures to avoid a certain assessment. If you’re adjusting the pressure 

periodically, you need to ... make that part of your overall assessment of the risk on that 

pipeline.” The CPUC director of consumer protection and safety division stated that the CPUC 

did not agree with the PG&E interpretation of 49 CFR 192.917, and commented that the practice 

of “artificially raising the pressure in a pipe that has identified integrity seam issues seems to be 

a wrong-headed approach to safety.” PHMSA officials were unaware of any other operators 

following such a practice.

 58 Federal Register, vol. 68, no. 18 (January 28, 2003), pp. 4278, 4318.

59 Federal Register, vol. 68, no. 240 (December 15, 2003), pp. 69817, 69791.

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A study that looked at the stability of manufacturing- and construction-related defects is 

discussed in Gas Research Institute (GRI)60

the risk of pressure-cycle-induced fatigue can be dismissed if and only if the 

pipeline has been subjected to a reasonably high-pressure hydrostatic test. 

Therefore, it would seem that eliminating the risk of failure from 

pressure-cycle-induced fatigue crack growth of defects that can survive an initial 

hydrostatic test of a pipeline requires that the test pressure level must be at least 

1.25 times the maximum operating pressure.

report GRI-04/0178, Effects of Pressure Cycles on 

Gas Pipelines, dated September 17, 2004:

A PHMSA report from 2007, No. 05-12R, Evaluating the Stability of Manufacturing and 

Construction Defects in Natural Gas Pipelines, also looked at defect stability and concluded the 

following:

To summarize, experience and scientific analysis indicates that manufacturing 

defects in gas pipelines that have been subjected to a hydrostatic test to 1.25 times 

MAOP should be considered stable. No integrity assessment is necessary to 

address that particular threat in such pipelines. The principal challenge for 

deciding whether or not to consider manufacturing defects to be stable is 

associated with those gas pipelines that have never been subjected to a hydrostatic

test to a minimum of 1.25 times MAOP.

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

On May 20, 2011,61 the NTSB learned that a DSAW segment on Line 132 had 

experienced a longitudinal seam leak in October 1988 at MP 30.44, about 8.78 miles south of the 

San Bruno rupture. Until May 6, 2011, the PG&E GIS had listed the cause of the leak as 

“unknown.” However, as a result of records discovered during a PG&E postaccident records 

search,62

Seam leaks or test failures in PG&E gas transmission pipelines are listed in table 2.

information was added to indicate that 12 feet of Line 132 had been replaced “due to a 

longitudinal defect.” A leak survey inspection and repair report dated October 27, 1988, 

classified the cause of the leak as a “material failure” and indicated that a material failure report 

was prepared, but PG&E could not locate any such report. Records showed that the replacement 

work had started on November 1 and been completed on November 4, 1988. No further 

information was available regarding the cause of the leak.

 60 In 2000, the GRI combined with the Institute of Gas Technology to form the Gas Technology Institute (GTI), 

a nonprofit research and development organization that develops, demonstrates, and licenses new energy 

technologies for private and public clients, with a particular focus on the natural gas industry. PG&E is a member of 

the GTI.

61 Shortly after the September 9, 2010, rupture, NTSB investigators asked PG&E to provide a leak/repair 

history for Line 132. However, this information was not provided until 8 months after the accident.

62 For more information about this records search, see Section 1.11.1, “Actions Taken by PG&E.” 

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

Year Found Line

Pipeline Diameter

(inches) Description

1948 132 30 Multiple longitudinal seam cracks found during 

radiography of girth welds during construction

1958 300B 34 Seam leak in DSAW pipe

1974 300B 34 Hydrostatic test failure of seam weld with lack of 

penetration (similar to accident pipe)

1988 132 30 Longitudinal seam defect in DSAW pipe

1992 132 30 Longitudinal seam defect in DSAW weld when a tie-in 

girth weld was radiographed 

1996 109 22 Cracking of the seam weld in DSAW pipe

1996 109 22 Seam weld with lack of penetration (similar to accident 

pipe) found during camera inspection

1996 DFM-3 -- Defect in forge-welded seam weld

1999 402 16 Leak in ERW seam weld

2011 300A 34 Longitudinal seam crack in 2-foot pup of DSAW pipe 

(found during camera inspection)

2011 153 30 Longitudinal seam defect in DSAW pipe during 

radiographic inspection for validation of seam type 

1.7.7 Protection Against Accidental Overpressure

Title 49 CFR 192.195, “Protection Against Accidental Overpressuring,” requires “each 

pipeline that is connected to a gas source so that [MAOP] could be exceeded as the result of 

pressure control failure or of some other type of failure, must have pressure relieving or pressure 

limiting devices that meet the requirements of [sections] 192.199 and 192.201.” Section 192.201,

in turn, requires—for pipelines operated at 60 psig or higher—that such devices must ensure that 

the pipeline pressure does not exceed MAOP plus 10 percent, or the pressure that produces a 

hoop stress of 75 percent of SMYS, whichever is lower.

1.8 Examination of Accident Pipe

The ruptured section of pipe and two cutout sections of pipe, immediately south and 

north of the ruptured section, as illustrated in the figure 18 schematic, were examined at the 

NTSB Materials Laboratory. The southern63 section of pipe consisted of a single portion of pipe 

(commonly referred to as a joint).

64

 63 “Southern” refers to the north-south alignment of the pipeline prior to the accident.

The center section (the ruptured section found about 100 feet 

from the crater) was fractured at both ends and comprised a continuation of the same long joint 

from the southern section as well as four shorter lengths of pipe (pups). The northern section of 

pipe comprised two more pups and a portion of another long joint. For convenience, the pups 

were numbered 1–6 in the south-to-north direction. The girth welds that joined the pups were 

numbered sequentially from south to north as C1, C2, and so on through C7.

64 A joint is a single length of pipe, typically 20 feet or greater in length.

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