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pdfNOTICE: This report is required by 49 CFR Part 191. Failure to report can result in a civil penalty as provided in 49
USC 60122.
INCIDENT REPORT –
GAS TRANSMISSION, GAS GATHERING,
AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
U.S. Department of Transportation
Pipeline and Hazardous Materials
Safety Administration
OMB NO: 2137- 0635
Expires: 06/30/2026
Report Date
No.
(DOT Use Only)
A federal agency may not conduct or sponsor, and a person is not required to respond to, nor shall a person be subject to a penalty for failure to
comply with a collection of information subject to the requirements of the Paperwork Reduction Act unless that collection of information displays
a current valid OMB Control Number. The OMB Control Number for this information collection is 2137-0635. Public reporting for this collection
of information is estimated to be approximately 12 hours per response, including the time for reviewing instructions, gathering the data needed,
and completing and reviewing the collection of information. All responses to this collection of information are mandatory. Send comments
regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden to: Information
Collection Clearance Officer, PHMSA, Office of Pipeline Safety (PHP-30) 1200 New Jersey Avenue, SE, Washington, D.C. 20590.
INSTRUCTIONS
Use this form for Type A, B, and C gas gathering. Type R gas gathering is reported on Form PHMSA F 7100.2-2.
Important:
Please read the separate instructions for completing this form before you begin. They clarify the information requested and provide
specific examples. If you do not have a copy of the instructions, you can obtain one from the PHMSA Pipeline Safety Community Web Page at
http://www.phmsa.dot.gov/pipeline/library/forms
PART A – KEY REPORT INFORMATION
Report Type: (select all that apply)
A1. Operator’s OPS-issued Operator Identification Number (OPID):
/
/
/
Original
/
/
Supplemental
Final
/
A2. Name of Operator: auto-populated based on OPID
A3. Address of Operator:
A3a. Street Address:
A3b. City:
A3c. State:
A3d. Zip Code:
auto-populated based on OPID
auto-populated based on OPID
auto-populated based on OPID
auto-populated based on OPID
A4. Local time (24-hr clock) and date of incident :
/
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/
Hour
/
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/
/
Month
/
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Day
/
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/
Year
A4a. Time Zone for local time (select only one) Alaska
A4b. Daylight Saving in effect?
A5. Location of Incident:
Latitude:
/ / / . / /
Longitude: - / / / / . /
/
Eastern Central Hawaii-Aleutian
Mountain Pacific.
Yes No
/
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A6. Gas released: (select only one, based on predominant volume released)
Natural Gas
Propane Gas
Synthetic Gas
Hydrogen Gas
Landfill Gas
Other Gas
Name:
A7. Estimated volume of gas released unintentionally:
/
A8. Estimated volume of intentional and controlled release/blowdown :
A9. Estimated volume of accompanying liquid released:
Form PHMSA F 7100.2 (rev 6-2023)
/
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/,/
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Reproduction of this form is permitted
/ thousand standard cubic feet (mcf)
/ thousand standard cubic feet (mcf)
/
/ Barrels
Page 1 of 22
A10. Were there fatalities? Yes No
If Yes, specify the number in each category:
A10a. Operator employees
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/
A10b. Contractor employees
working for the Operator
/
/
/
/
A10c. Non-Operator
emergency responders
/
/
/
A10d. Workers working on the
right-of-way, but NOT
associated with this Operator
/
/
A10e. General public
/
/
A10f. Total fatalities (sum of above)
calculated
A11. Were there injuries requiring inpatient hospitalization?
No
If Yes, specify the number in each category:
Yes
A11a. Operator employees
/
/
/
/
/
/
A11b. Contractor employees
working for the Operator
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/
A11c. Non-Operator
emergency responders
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A11d. Workers working on the
right-of-way, but NOT
associated with this Operator
/
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/
A11e. General public
/
/
/
/
/
A11f. Total injuries (sum of above)
calculated
A12. What was the Operator’s initial indication of the Failure? (select only one)
SCADA-based information (such as alarm(s), alert(s), event(s), and/or volume calculations)
Static Shut-in Test or Other Pressure or Leak Test
Controller
Local Operating Personnel, including contractors
Air Patrol
Ground Patrol by Operator or its contractor
Notification from Public
Notification from Emergency Responder
Notification from Third Party that caused the Incident
Other _________________________________________________
A12a. If “Controller”, “Local Operating Personnel, including contractors”, “Air Patrol”, or “Ground Patrol by Operator or its contractor” is selected in
Question 12, specify the following: (select only one)
Operator employee
Contractor working for the Operator
A13. Local time Operator identified failure
/
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Hour
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Month
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Day
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/
Year
A14. Part of system involved in Incident: (select only one)
Belowground Storage, Including Associated Equipment and Piping
Aboveground Storage, Including Associated Equipment and Piping
Onshore Compressor Station Equipment and Piping
Onshore Regulator/Metering Station Equipment and Piping
Onshore Pipeline, Including Valve Sites
Offshore Platform, Including Platform-mounted Equipment and Piping
Offshore Pipeline, Including Riser and Riser Bend
A15. Operational Status at time Operator identified failure (select only one)
Post-Construction Commissioning
Post-Maintenance/Repair
Routine Start-Up
Routine Shutdown
Normal Operation, includes pauses during maintenance
Idle
A16. If A15 = Routine Start-Up or Normal Operation, was the pipeline/facility shut down due to the incident?
Yes No Explain: ______________________________________________________________________________
If Yes, complete Questions A16.a and A16.b: (use local time, 24-hr clock)
A16a. Local time and date of shutdown
/
A16b. Local time pipeline/facility restarted
/
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Hour
Hour
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Month
Month
Day
Day
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/
Year
Year
Still shut down*
*Supplemental Report required
If A12. = Notification from Emergency Responder, skip A17.
A17a. Did the operator communicate with Local, State, or Federal Emergency Responders about the incident?
Yes
No
If No, skip A17b and c.
A17b. Which party initiated communication about the incident?
Operator
Local/State/Federal Emergency Responder
A17c. Local time of initial Operator and Local/State/Federal Emergency Responder communication
/ / / / /
/
Hour
A18. Local time operator resources arrived on site
A19. Local time of confirmed discovery
Form PHMSA F 7100.2 (rev 6-2023)
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Hour
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Hour
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Month
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Month
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Month
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Reproduction of this form is permitted
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Year
Day
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Day
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Year
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Year
Page 2 of 22
A20a. Local time (24-hr clock) and date of initial operator report to the National Response Center :
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Hour
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Month
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Day
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Year
/
A20b. Initial Operator National Response Center Report Number _____________________OR
NRC Notification Required But Not Made
A20c. Additional NRC Report numbers submitted by the operator:_____________________
A21. Did the gas ignite?
Yes
No
If A21 = Yes, then answer A21a through d:
A21a.
Local time of ignition
/
/
/
Hour
/
/
/
/
Month
/
/
/
Day
A21b. How was the fire extinguished?
Operator/Contractor Local/State/Federal Emergency Responder
A21c. Estimated volume of gas consumed by fire (mcf):
A21d. Did the gas explode?
Yes
/
/
/
Year
/
Allowed to burn out Other, specify:_________
(must be less than or equal to A7.)
No
If A14. is “Onshore Pipeline, Including Valve Sites” OR “Offshore Pipeline, Including Riser and Riser Bend”, answer A22a through f
A22a. Initial action taken to control flow upstream of failure location
If Valve Closure, answer A22.b and c:
A22b. Local time of final upstream valve closure
/ / /
Hour
Valve Closure
/
/
/
/
Month
Operational Control - mandatory text field
/
/
/
Day
/
/
/
Year
/
A22c. Type of upstream valve used to complete upstream isolation of release source:
Manual Automatic
Remotely Controlled
A22d. Initial action taken to control flow downstream of failure location
If Valve Closure, answer A22e and f.:
A22e. Local time of final downstream valve closure
/
/
/
/
Hour
/
Valve Closure
/
/
Month
Operational Control - mandatory text field
/
/
/
Day
A22f. Type of downstream valve used to complete downstream isolation of release source:
Manual Automatic
Remotely Controlled
A23. Number of general public evacuated: /
Form PHMSA F 7100.2 (rev 6-2023)
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Year
/
Check Valve
/
Reproduction of this form is permitted
Page 3 of 22
PART B – ADDITIONAL LOCATION INFORMATION
B1. Was the origin of the Incident onshore? Auto-populated based on A14
Yes (Complete Questions B2-B11)
No (Complete Questions B12-B14)
B1a. Pipeline/Facility name: _______________________________
B1b. Segment name/ID: __________________________________
If Onshore:
B2. State: /
/
/
B3. Zip Code: /
B4 ______________________
City
/
/
/
/
/
/
/
/
B5______________________
County or Parish
B6. Operator designated location: (select only one)
B7.
/ - /
Milepost (specify in shaded area below)
Survey Station No. (specify in shaded area below)
Not Applicable (B7 will not accept data)
/___/___/___/___/___/___/___/___/___/___/___/___/___/
Yes
B8. Was Incident on Federal land, other than the Outer Continental Shelf (OCS)?
B9. Location of Incident: (select only one)
Operator-controlled property
No
Pipeline right-of-way
B10. Area of Incident (as found): (select only one)
Belowground storage or aboveground storage vessel, including attached appurtenances
Underground Specify: Under soil Under a building
Under pavement
Exposed due to excavation
Exposed due to loss of cover In underground enclosed space (e.g., vault) Other ________________
B10a. Depth-of-Cover (in): /
/,/
/
/
/
B10.b. Were other underground facilities found within 12 inches of the failure location? Yes
No
Typical aboveground facility piping or appurtenance
Overhead crossing
In or spanning an open ditch Inside a building O Inside other enclosed space O Other _______________
Transition Area Specify: Soil/air interface Wall sleeve Pipe support or other close contact area
Other ____________________________
Aboveground
Specify:
B11. Did Incident occur in a crossing?
Yes
No
If Yes, specify type:
Bridge crossing Specify: Cased Uncased
Railroad crossing (select all that apply) Cased
Road crossing
(select all that apply) Cased
Water crossing
Specify:
Cased
Uncased
Uncased
Bored/drilled
Bored/drilled
Uncased
Name of body of water, if commonly known: ______________________
Approx. water depth (ft) at the point of the Incident: / /,/ / / / OR Unknown
(select only one of the following)
Shoreline/Bank/Marsh crossing
Below water, pipe in bored/drilled crossing
Below water, pipe buried below bottom (NOT in bored/drilled crossing)
Below water, pipe on or above bottom
Is this water crossing 100 feet or more in length from high water mark to high water mark?
Yes No
If Offshore:
B12. Approximate water depth (ft.) at the point of the Incident:
B13. Origin of Incident:
In State waters Specify: State: /
/
/
/
/,/
/
Area: _________
/
/
Block/Tract #: /___/___/___/___/
Nearest County/Parish: ________________
On the Outer Continental Shelf (OCS) ) (select only one)
Area: ___________________
OCS – Alaska
OCS-Gulf of Mexico
Block/Tract #: /___/___/___/___/
OCS- Atlantic
OCS – Pacific
B14. Area of Incident: (select only one)
Shoreline/Bank/Marsh crossing or shore approach
Below water, pipe buried or jetted below seabed
Below water, pipe on or above seabed
Splash Zone of riser
Portion of riser outside of Splash Zone, including riser bend
Platform
Form PHMSA F 7100.2 (rev 6-2023)
Reproduction of this form is permitted
Page 4 of 22
PART C – ADDITIONAL FACILITY INFORMATION
C1. Is the pipeline or facility:
Interstate
Intrastate
C2. Material involved in Incident: (select only one)
Carbon Steel
Plastic
Material other than Carbon Steel or Plastic
*Specify: ____________________________________________
C3. Item involved in Incident: (select only one)
Pipe
Specify:
Pipe Body
If Pipe Body: Was this a Puddle/Spot Weld?
If C2. is Carbon Steel
C3b. Wall thickness (in):
/
Pipe Seam
Yes No
/./
/
/
C3a. Nominal Pipe Size:
/
C3d. Pipe specification: _____________________________
OR
/
/
Longitudinal ERW – Unknown Frequency
Spiral Welded
Lap Welded
C3g. Pipeline coating type at point of Incident
Epoxy
Specify:
/,/
/
/
Seamless
/
/
/
Other ________________
Unknown
Coal Tar
Cold Applied Tape
Other _______________________________
Yes No Unknown
If C2. is Plastic
C3i. If Plastic Specify type:
/
Single SAW Flash Welded
DSAW
Continuous Welded Furnace Butt Welded
C3f. Pipe manufacturer: _______________________________ OR
C3h. Coating field applied?
/./
Unknown
Specify: Longitudinal ERW - High Frequency
Longitudinal ERW - Low Frequency
Extruded Polyethylene
/
/
C3c. SMYS (Specified Minimum Yield Strength) of pipe (psi):
C3e. Pipe Seam
/
Asphalt
Paint
Polyolefin
Composite None
Polyvinyl Chloride (PVC)
Polyethylene (PE)
Cross-linked Polyethylene (PEX)
Polybutylene (PB)
Polypropylene (PP)
Acrylonitrile Butadiene Styrene (ABS)
Polyamide (PA)
Cellulose Acetate Butyrate (CAB)
Unknown
Other: mandatory text field_
C3j. If Plastic Specify Standard Dimension Ratio (SDR): /
/
/
/
/
or wall thickness: /
/./
/
/
/
or
Unknown
C3k. If Polyethylene (PE) is selected as the type of plastic in C3j, specify PE Pipe Material Designation Code (i.e., 2406, 3408, etc.)
/ / / or Unknown
PE /
Weld/Fusion, including heat-affected zone
Specify: Pipe Girth Weld Pipe Plastic Fusion Other Butt Weld Fillet Weld
If Pipe Girth Weld is selected, complete items C3.a through h above.
Are any of the C3b through h values different on either side of the girth weld? Yes No
If Yes, enter the different value(s) below:
C3l. Wall thickness (in):
/
/./
/
/
/
C3m. SMYS (Specified Minimum Yield Strength) of pipe (psi):
/
C3n. Pipe specification: _____________________________ OR
/
/
/,/
/
/
/
Unknown
Specify: Longitudinal ERW - High Frequency Single SAW Flash Welded
Longitudinal ERW - Low Frequency DSAW Continuous Welded Longitudinal ERW – Unknown
Furnace Butt Welded Spiral Welded Lap Welded
Seamless Other, describe: ________________________
C3o. Pipe Seam
C3p. Pipe manufacturer: _______________________________
OR
Frequency
Unknown
C3q. Pipeline coating type at point of Accident
Specify: Fusion Bonded Epoxy (FBE)
Coal Tar Asphalt Polyolefin Extruded Polyethylene
Epoxy other than FBE Cold Applied Tape Paint Composite None Other, describe: _______________
C3r. Coating field applied?
Yes
No
Unknown
If Plastic Pipe Fusion is selected, complete items C3.a and c3.i through k above.
Form PHMSA F 7100.2 (rev 6-2023)
Reproduction of this form is permitted
Page 5 of 22
/
Valve, excluding Regulator/Control Valves
Mainline Specify: Butterfly Check
Relief Valve
Auxiliary or Other Valve
Gate
Plug
C3s. Mainline valve manufacturer:
Ball Globe Other _______________
OR Unknown
Compressor, including auxiliary piping, connections, valves, and equipment, but excluding product drain lines and tubing.
Meter, including auxiliary piping, connections, valves, and equipment, but excluding product drain lines and tubing.
Scraper/Pig Trap, including auxiliary piping, connections, valves, and equipment, but excluding product drain lines and tubing.
Odorization System, including auxiliary piping, connections, valves, and equipment, but excluding product drain lines and tubing.
Filter/Strainer/Separator, including auxiliary piping, connections, valves, and equipment, but excluding product drain lines and tubing.
Dehydrator/Drier/Treater/Scrubber, including auxiliary piping, connections, valves, and equipment, but excluding product drain lines and
Regulator/Control Valve, including auxiliary piping, connections, valves, and equipment, but excluding product drain lines and tubing.
Pulsation Bottle or Drip/Drip Collection Device
Cooler or Heater, including auxiliary piping, connections, valves, and equipment, but excluding product drain lines and tubing.
Repair Sleeve or Clamp
Hot Tap Equipment
Tap Fitting (stopple, thread-o-ring, weld-o-let, etc.)
Flange Assembly, including Gaskets
ESD System, including auxiliary piping, connections, valves, and equipment, but excluding product drain lines and tubing.
Drain Lines
Tubing, including Fittings
C3t. Tubing material (select only one):
Stainless steel
Carbon steel
Copper
Other
C3u. Type of tubing (select only one):
Rigid
Flexible
Instrumentation, including Programmable Logic Controllers and Controls
Underground Gas Storage or Cavern
Other ___________________________________
tubing.
C4. Year item involved in Incident was installed:
/
C5. Year item involved in Incident was manufactured:
/
/
/
/
/
Unknown
/ OR
/
/
/
Unknown
OR
C6. Type of release involved: (select only one)
Mechanical Puncture
Approx. size: /__/__/__/__/./__/in. (axial) by /__/__/__/__/./__/in. (circumferential)
Pinhole
Crack
Rupture Select Orientation: Circumferential
Leak
Select Type:
Connection Failure
Seal or Packing
Other
Longitudinal
Other ________________________________
Approx. size: /__/__/__/__/./__/ in. (widest opening) by /__/__/__/__/__/./__/in. (length circumferentially or axially)
Other
*Describe: ___________________________________________________________________
PART D – ADDITIONAL CONSEQUENCE INFORMATION
D1. Class Location of Incident: (select only one)
Class 1 Location
Class 2 Location
Class 3 Location
Class 4 Location
D2. Did this Incident occur in a High Consequence Area (HCA)?
No
Yes D2.a Specify the Method used to identify the HCA:
Method 1(Class Location)
Method 2 (PIR)
Not Flammable
Yes
Were any structures outside the PIR impacted or otherwise damaged NOT by heat/fire resulting from the Incident? Yes
Were any of the fatalities or injuries (A11 only) reported for persons located outside the PIR?
Yes
D3. What is the PIR (Potential Impact Radius) for the location of this Incident?
/
/,/
/
/
/ feet
or
D4. Were any structures outside the PIR impacted or otherwise damaged by heat/fire resulting from the Incident?
D5.
D6.
If Yes, Describe the cause of the fatalities or injuries: ______________________________________
D13. If D2. Is No, answer D13a.
D13a. Did this incident occur in a Moderate Consequence Area (MCA)?
Yes
No
No
No
No
If D13a. is Yes, answer D13b.
D13b. Select each of the items below that were present within the potential impact circle:
5 or more buildings intended for human occupancy
Paved surface for a designated interstate, freeway, expressway, or other principal 4-lane arterial roadway
Form PHMSA F 7100.2 (rev 6-2023)
Reproduction of this form is permitted
Page 6 of 22
D7. Estimated Property Damage:
D7a. Estimated cost of public and non-Operator private property damage
$/
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/,/
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/
D7b. Estimated cost of Operator’s property damage & repairs
$/
/
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/
D7c. Estimated cost of emergency response
$/
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/
D7d. Estimated other costs
$/
/
/
/,/
/
/
/,/
/
/
/
Describe: _______________________________
D7e. Total estimated property damage (sum of above)
$ calculated
Cost of Gas Released
Cost of Gas in $ per thousand standard cubic feet (mcf): ______________
D7f. Estimated cost of gas released unintentionally
$ calculated
D7g. Estimated cost of gas released during intentional and controlled blowdown
$ calculated
D7h. Total estimated cost of gas released (sum of 7.f & 7.g above)
$ calculated
D7i. Estimated Total Cost (sum of D7e and D7h)
$ calculated
Injured Persons not included in A11 The number of persons injured, admitted to a hospital, and remaining in the hospital for at least one overnight
are reported in A11. If a person is included in A11, do not include them in D8.
D8. Estimated number of persons with injuries requiring treatment in a medical facility but not requiring overnight in-patient hospitalization:
If a person is included in D8, do not include them in D9.
D9. Estimated number of persons with injuries requiring treatment by EMTs at the site of incident:
Buildings Affected
D10. Number of residential buildings affected (evacuated or required repair or gas service interrupted):
D11. Number of business buildings affected (evacuated or required repair or gas service interrupted):
Yes No
D12. Wildlife impact:
D12a. If Yes, specify all that apply:
Fish/aquatic
Birds
Terrestrial
Form PHMSA F 7100.2 (rev 6-2023)
Reproduction of this form is permitted
Page 7 of 22
PART E – ADDITIONAL OPERATING INFORMATION
E1. Estimated pressure at the point and time of the Incident (psig):
/
/
/,/
E1a. Estimated gas flow in pipe segment at the point and time of the incident (MSCF/D):
/
/
/
E2. Maximum Allowable Operating Pressure (MAOP) at the point and time of the Incident (psig) :
/
/
/,/
E2a.
MAOP established by 49 CFR section:
� 192.619 (a)(1) � 192. 619 (a)(2) � 192. 619 (a)(3) � 192.619 (a)(4)
� 192.624 (c)(1) � 192. 624(c)(2) � 192.624 (c)(3) � 192.624 (c)(4)
� Other
Specify Other:
E2b.
Date MAOP established:
/
/
Month
/
/
/
Day
/
/
/
Year
/
/
/
/
/
/
/
/
/
� 192. 619 (c)
� 192.619 (d)
� 192.624(c)(5) � 192.624 (c)(6)
/
E2c. Was the MAOP in E2a and b established in conjunction with a reversal of flow direction?
Yes No
Bi-Directional
E3. Describe the pressure on the system or facility relating to the Incident: (select only one)
Pressure did not exceed MAOP
Pressure exceeded MAOP, but did not exceed the applicable allowance in §192.201
Pressure exceeded the applicable allowance in §192.201
E4. Was the system or facility relating to the Incident operating under an “established pressure restriction” with pressure limits below those normally
allowed by the MAOP ?
No Yes (Complete E4.a and E4.b below)
E4a. Did the pressure exceed this “established pressure restriction?”
E4b. Was this pressure restriction mandated by PHMSA or the State?
Yes
No
PHMSA
State
E5. Was the gas at the point of failure required to be odorized in accordance with §192.625?
If yes, Was the gas at the point of failure odorized in accordance with §192.625?
Not mandated
Yes No
Yes No
If A14. is “Onshore Pipeline, Including Valve Sites” OR “Offshore Pipeline, Including Riser and Riser Bend”, answer E6 through E8.
E6. Length of segment between upstream and downstream shut-off valves closest to failure location (ft):
/
/
/
/,/
/
/
/
E7 Is the pipeline configured to accommodate internal inspection tools?
Yes
No Which physical features limit tool accommodation? (select all that apply)
Changes in line pipe diameter
Presence of unsuitable mainline valves
Tight or mitered pipe bends
Other passage restrictions (i.e. unbarred tee’s, projecting instrumentation, etc.)
Extra thick pipe wall (applicable only for magnetic flux leakage internal inspection tools)
Other Describe:______________________________
E8 For this pipeline, are there operational factors which significantly complicate the execution of an internal inspection tool run?
No
Yes
Which operational factors complicate execution?
(select all that apply)
Excessive debris or scale, wax, or other wall build-up
Low operating pressure(s)
Low flow or absence of flow
Incompatible commodity
Other Describe:_______________________________
E9 Function of pipeline system: (select only one)
Transmission System
Transmission Line of Distribution System
Type A Gathering
Type B Gathering
Type C Gathering
Transmission in Storage Field
Offshore Gathering
Form PHMSA F 7100.2 (rev 6-2023)
Reproduction of this form is permitted
Page 8 of 22
E10 Was a Supervisory Control and Data Acquisition (SCADA)-based system in place on the pipeline or facility involved in the Incident?
No
Yes E10.a Was it operating at the time of the Incident?
Yes
No
E10.b Was it fully functional at the time of the Incident?
Yes
No
E10.c Did SCADA-based information (such as alarm(s), alert(s), event(s), and/or volume or pack calculations) assist with
the initial indication of the Incident?
Yes
No
E10.d Did SCADA-based information (such as alarm(s), alert(s), event(s), and/or volume calculations) assist with the
confirmed discovery of the Incident?
Yes
No
E11 Was an investigation initiated into whether or not the controller(s) or control room issues were the cause of or a contributing factor to the Incident?
(select only one)
Yes, but the investigation of the control room and/or controller actions has not yet been completed by the operator (Supplemental Report
required)
No, the facility was not monitored by a controller(s) at the time of the Incident
No, the operator did not find that an investigation of the controller(s) actions or control room issues was necessary due to: (provide an
explanation for why the operator did not investigate): ______________________________________________
Yes, specify investigation result(s): (select all that apply)
Investigation reviewed work schedule rotations, continuous hours of service (while working for the Operator) and other factors
associated with fatigue
Investigation did NOT review work schedule rotations, continuous hours of service (while working for the Operator) and other
factors associated with fatigue (provide an explanation for why not): _________________________________
Investigation identified no control room issues
Investigation identified no controller issues
Investigation identified incorrect controller action or controller error
Investigation identified that fatigue may have affected the controller(s) involved or impacted the involved controller(s) response
Investigation identified incorrect procedures
Investigation identified incorrect control room equipment operation
Investigation identified maintenance activities that affected control room operations, procedures, and/or controller response
Investigation identified areas other than those above Describe: ____________________________________
PART F – DRUG & ALCOHOL TESTING INFORMATION
F1. As a result of this Incident, were any Operator employees tested
under the post-accident drug and alcohol testing requirements of
DOT’s Drug & Alcohol Testing regulations?
No
Yes
F1a. Specify how many were tested:
/
/
/
F1b. Specify how many failed:
/
/
/
F2. As a result of this Incident, were any Operator contractor
employees tested under the post-accident drug and alcohol testing
requirements of DOT’s Drug & Alcohol Testing regulations?
No
Yes
F2a. Specify how many were tested:
/
/
/
F2b. Specify how many failed:
/
/
/
Form PHMSA F 7100.2 (rev 6-2023)
Reproduction of this form is permitted
Page 9 of 22
PART G – APPARENT CAUSE
Select only one box from PART G in the shaded column on the
left representing the APPARENT Cause of the Incident, and
answer the questions on the right. Enter secondary, contributing,
or root causes of the Incident in Part K – Contributing Factors.
G1 - Corrosion Failure – only one sub-cause can be picked from
shaded left-hand column
External Corrosion
1. Results of visual examination:
Localized Pitting General Corrosion
Other
________________________________________________________
_____
2. Type of corrosion: (select all that apply)
Galvanic Atmospheric Stray Current
Microbiological Selective Seam
Other
________________________________________________________
_____
2a. If 2 is Stray Current, specify Alternating Current Direct
Current AND
2b. Describe the stray current source:
___________________________________________
3. The type(s) of corrosion selected in Question 2 is based on the
following: (select all that apply)
Field examination
Determined by metallurgical analysis
Other
________________________________________________________
_____
4. Was the failed item buried or submerged?
Yes 4a. Was failed item considered to be under cathodic
protection at the time of
the incident?
Yes Year protection started: / / /
/
/
No
4b. Was shielding, tenting, or disbonding of coating
evident at the point of
the incident?
Yes No
4c. Has one or more Cathodic Protection Survey been
conducted at
the point of the incident? (select all that apply)
Yes, CP Annual Survey Most recent year
conducted:
/ / / / /
Yes, Close Interval Survey Most recent year
conducted: / / / / /
Yes, Other CP Survey Most recent year
conducted:
/ / / / /
Describe other CP survey
____________________________________
No
No
Yes No
4d. Was the failed item externally coated or painted?
5. Was there observable damage to the coating or paint in the vicinity
of the corrosion?
Yes No N/A Bare/Ineffectively Coated Pipe
Internal Corrosion
6. Results of visual examination:
Localized Pitting
General Corrosion
Not cut open
Other
________________________________________________________
____
7. Cause of corrosion: (select all that apply)
Corrosive Commodity Water drop-out/Acid
Microbiological Erosion
Other ____________
________________________________________________
Form PHMSA F 7100.2 (rev 6-2023)
Reproduction of this form is permitted
Page 10 of 22
8. The cause(s) of corrosion selected in Question 7 is based on the
following: (select all that
apply)
Field examination
Determined by metallurgical analysis
Other
________________________________________________________
_____
9. Location of corrosion: (select all that apply)
Low point in pipe Elbow Drop-out Dead-Leg
Other
________________________________________________________
____
10. Was the gas/fluid treated with corrosion inhibitors or biocides?
Yes No
11. Was the interior coated or lined with protective coating?
No
Yes
12. Were cleaning/dewatering pigs (or other operations) routinely
utilized?
Not applicable - Not mainline pipe
Yes
No
13. Were corrosion coupons routinely utilized?
Not applicable - Not mainline pipe
Yes
Form PHMSA F 7100.2 (rev 6-2023)
Reproduction of this form is permitted
No
Page 11 of 22
G2 - Natural Force Damage - only one sub-cause can be picked from shaded left-hand column
1. Specify: Earthquake Subsidence
Other __________________
Landslide
Earth Movement, NOT due to Heavy Rains/Floods
Heavy Rains/Floods
2. Specify: Washout/Scouring
Other _______________
Lightning
3. Specify:
nearby fires
Direct hit Secondary impact such as resulting
Temperature
4. Specify:
Thermal Stress
Frozen Components
Flotation Mudslide
________________________________
High Winds
Trees/Vegetation Roots
Frost Heave
Other
Snow/Ice impact or Accumulation
5. Describe: __________________________
Other Natural Force Damage
Complete the following if any Natural Force Damage sub-cause is selected.
6. Were the natural forces causing the Incident generated in conjunction with an extreme weather event?
6a. If Yes, specify: (select all that apply)
Form PHMSA F 7100.2 (rev 6-2023)
Yes
No
Hurricane Tropical Storm
Tornado
Other ______________________________
Reproduction of this form is permitted
Page 12 of 22
G3 – Excavation Damage - only one sub-cause can be picked from shaded left-hand column
Excavation Damage by Operator (First Party)
Excavation Damage by Operator’s Contractor (Second
Party)
Excavation Damage by Third Party
Previous Damage due to Excavation Activity
Complete the following if any Excavation Damage suc-cause is selected.
1. Did the operator get prior notification of the excavation activity?
Yes No
1a. If Yes, Notification received from: (select all that apply) One-Call System
Excavator Contractor
1b. Per the primary Incident Investigator results, did State law exempt the excavator from notifying the one-call center?
Unknown
If yes, answer 1c. through 1e.
1c. select one of the following:
Excavator is exempt
Activity is exempt and did not exceed the limits of the exemption
Activity is exempt and exceeded the limits of the exemption
Other mandatory text field: _______________________________________
1d. Exempting authority
_
1e. Exempting criteria
___
2. Do you want PHMSA to upload the following information to CGA-DIRT (www.cga-dirt.com)?
Yes
Landowner
Yes No
No
3. Right-of-Way where event occurred: (select all that apply)
Public Specify: City Street State Highway County Road Interstate Highway
Private Specify: Private Landowner Private Business Private Easement
Pipeline Property/Easement
Power/Transmission Line
Railroad
Dedicated Public Utility Easement
Federal Land
Unknown/Other
4 Was the facility part of a Joint Trench? Yes
5. Did this event involve a Cross Bore? Yes
Other
No
No
6. Measured Depth from Grade: (select only one)
Embedded in Concrete/Asphalt Pavement <18”
18” – 36”
>36”
Measured depth From Grade in inches:__________
7. Type of excavator: (select only one)
Contractor
Railroad
County
State
Developer
Utility
Farmer
Municipality
Unknown/Other
Occupant
8. Type of excavation equipment: (select only one)
Auger
Explosives
Probing Device
Backhoe/Trackhoe
Farm Equipment
Trencher
Boring
Grader/Scraper
Vacuum Equipment
Drilling
Hand Tools
Unknown/Other
Directional Drilling
Milling Equipment
9. Type of work performed: (select only one)
Agriculture
Cable TV
Curb/Sidewalk
Drainage
Driveway
Electric
Grading
Irrigation
Landscaping
Natural Gas
Pole
Public Transit Authority
Sewer (Sanitary/Storm) Site Development
Steam
Telecommunications
Traffic Signal
Traffic Sign
Unknown/Other
Form PHMSA F 7100.2 (rev 6-2023)
Building Construction
Engineering/Surveying
Liquid Pipeline
Railroad Maintenance
Storm Drain/Culvert
Water
Reproduction of this form is permitted
Building Demolition
Fencing
Milling
Road Work
Street Light
Waterway Improvement
Page 13 of 22
10. Was the One-Call Center notified?
Yes
*10a. If Yes, specify ticket number: /
/
No
/
/
/
If No, skip to question 11
/
/
/
/
/
/
/
/
/
/
/
/
/
/
*10b. If this is a State where more than a single One-Call Center exists, list the name of the One-Call Center notified:
_____________________________________________________________
10c. Was work area white lined?
11. Type of Locator:
No
Facility Owner
Yes
Unknown
Contract Locator
Unknown/Other
12. Were facility locate marks visible in the area of excavation?
No
Yes
Unknown/Other
13. Did the damage cause an interruption in service?
No
Yes
Unknown/Other
13a. If Yes, specify duration of the interruption:
/___/___/___/___/ hours
14. Description of the CGA-DIRT Root Cause (select the predominant CGA-DIRT Root Cause from the list below):
Notification Issue
No notification made to the One-Call Center/811
☐ Excavator dug outside area described on ticket
☐ Excavator dug prior to valid start date/time
☐ Excavator dug after valid ticket expired
☐ Excavator provided incorrect notification information
Excavation Issue
☐ Excavator dug prior to verifying marks by test-hole (pothole)
☐ Excavator failed to maintain clearance after verifying marks
☐ Excavator failed to protect/shore/support facilities
☐ Improper backfilling practices
☐ Marks faded or not maintained
☐ Improper excavation practice not listed above
Locating Issue
☐ Facility not marked due to Abandoned facility
☐ Facility not marked due to Incorrect facility records/maps
☐ Facility not marked due to Locator error
☐ Facility not marked due to No response from operator/contract locator
☐ Facility not marked due to Incomplete marks at damage location
☐ Facility not marked due to Tracer wire issue
☐ Facility not marked due to Unlocatable Facility
☐ Facility marked inaccurately due to Abandoned facility
☐ Facility marked inaccurately due to Incorrect facility records/maps
☐ Facility marked inaccurately due to Locator error
☐ Facility marked inaccurately due to Tracer wire issue
Miscellaneous Root Causes
☐ Deteriorated facility
☐ One Call Center Error
☐ Previous damage
☐ Root Cause not listed (comment required):
Form PHMSA F 7100.2 (rev 6-2023)
Reproduction of this form is permitted
Page 14 of 22
G4 - Other Outside Force Damage - only one sub-cause can be picked from shaded left-hand column
Nearby Industrial, Man-made, or Other Fire/Explosion as
Primary Cause of Incident
Damage by Car, Truck, or Other Motorized
Vehicle/Equipment NOT Engaged in Excavation
1. Vehicle/Equipment operated by: (select only one)
Operator
Operator’s Contractor
Third Party
If this sub-section is picked, please complete questions 5-11 below
Damage by Boats, Barges, Drilling Rigs, or Other Maritime
Equipment or Vessels Set Adrift or Which Have Otherwise
Lost Their Mooring
2. Select one or more of the following IF an extreme weather event
was a factor:
Hurricane
Tropical Storm
Tornado
Heavy Rains/Flood
Other
______________________________
Routine or Normal Fishing or Other Maritime Activity NOT
Engaged in Excavation
Electrical Arcing from Other Equipment or Facility
Previous Mechanical Damage NOT Related to Excavation
Intentional Damage
3. Specify:
Other Outside Force Damage
4. Describe:
________________________________________________________
_
Vandalism
Terrorism
Theft of transported commodity Theft of equipment
Other ________________________________________
Complete the following if Damage by Car, Truck, or Other Motorized Vehicle/Equipment NOT Engaged in Excavation sub-cause is selected.
5. Was the driver of the vehicle or equipment issued one or more citations related to the incident?
If 5 is Yes, what was the nature of the citations (select all that apply)
5a. Excessive Speed
5b. Reckless Driving
5c. Driving Under the Influence
5e. Other, describe: _______________________
6. Was the driver under control of the vehicle at the time of the collision?
Yes
Yes
No Unknown
No Unknown
7. Estimated speed of the vehicle at the time of impact (miles per hour)?_______________or Unknown
8. Type of vehicle? (select only one)
Motorcycle/ATV
Passenger Car Small Truck Bus Large Truck
9. Where did the vehicle travel from to hit the pipeline facility? (select only one)
Roadway
Driveway
Parking Lot
Loading Dock
Off-Road
10. Shortest distance from answer in 9. to the damaged pipeline facility (in feet): .________________________
11. At the time of the Incident, were protections installed to protect the damaged pipeline facility from vehicular damage?
Yes
No
If 11. is Yes, specify type of protection (select all that apply):
11a. Bollards/Guard Posts
11b. Barricades – include Jersey barriers and fences in instructions
11c. Guard Rails
11d. Other, describe: _________________________________
Form PHMSA F 7100.2 (rev 6-2023)
Reproduction of this form is permitted
Page 15 of 22
Use this section to report material failures ONLY IF the “Item
Involved in Incident” (from PART C, Question 3) is “Pipe” or
“Weld.”
G5 - Material Failure of Pipe or Weld
Only one sub-cause can be picked from shaded left-hand column
1. The sub-cause selected below is based on the following: (select all that apply)
Field Examination
Determined by Metallurgical Analysis
Other Analysis__________________________
Sub-cause is Tentative or Suspected; Still Under Investigation
(Supplemental Report required)
Design-, Construction-, Installation-, or Fabrication-related
Original Manufacturing-related
(NOT girth weld or other welds formed in the field)
Environmental Cracking-related
2. List contributing factors: (select all that apply)
Fatigue- or Vibration-related:
Mechanically-induced prior to installation (such as during
transport of pipe)
Mechanical Vibration
Pressure-related
Thermal
Other __________________________________
Mechanical Stress
Other __________________________________
3. Specify:
Cracking
Stress Corrosion Cracking
Sulfide Stress
Hydrogen Stress Cracking Hard Spot
Other ____________________________________
Complete the following if any Material Failure of Pipe or Weld sub-cause is selected.
4. Additional factors (select all that apply): Dent Gouge Pipe Bend
Lamination
Buckle
Wrinkle
Misalignment
Other __________________________________
5. Post-construction pressure test value (psig) /
Form PHMSA F 7100.2 (rev 6-2023)
/
/
/
/
OR
Arc Burn Crack
Burnt Steel
Lack of Fusion
Unknown
Reproduction of this form is permitted
Page 16 of 22
G6 - Equipment Failure - only one sub-cause can be picked from shaded left-hand column
Malfunction of Control/Relief Equipment
1. Specify: (select all that apply)
Control Valve
Instrumentation
SCADA
Communications
Block Valve
Check Valve
Relief Valve
Power Failure
Pressure Regulator
Stopple/Control Fitting
ESD System Failure
Other
________________________________________________________
Compressor or Compressor-related Equipment
2. Specify: Seal/Packing Failure
Crack in Body
Appurtenance Failure
Vessel Failure
Body Failure
Pressure
Other
_______________________________________________________
Threaded Connection/Coupling Failure
3. Specify: Pipe Nipple
Valve Threads
Mechanical Coupling
Threaded Fitting
Threaded Pipe Collar
Other
_______________________________________________________
Non-threaded Connection Failure
4. Specify: O-Ring
Gasket
compressor seal) or Packing
Seal (NOT
Other____________________________________________________
___
Defective or Loose Tubing or Fitting
Failure of Equipment Body (except Compressor), Vessel
Plate, or other Material
Other Equipment Failure
5. Describe:
________________________________________________________
___
________________________________________________________
_______________
Complete the following if any Equipment Failure sub-cause is selected.
6. Additional factors that contributed to the equipment failure: (select all that apply)
Excessive vibration
Overpressurization
No support or loss of support
Manufacturing defect
Loss of electricity
Improper installation
Improper maintenance
Mismatched items (different manufacturer for tubing and tubing fittings)
Dissimilar metals
Breakdown of soft goods due to compatibility issues with transported gas/fluid
Valve vault or valve can contributed to the release
Alarm/status failure
Misalignment
Thermal stress
Erosion/abnormal wear
Other _______________________________________________________
Form PHMSA F 7100.2 (rev 6-2023)
Reproduction of this form is permitted
Page 17 of 22
G7 - Incorrect Operation - only one sub-cause can be picked from shaded left-hand column
Damage by Operator or Operator’s Contractor NOT Related
to Excavation and NOT due to Motorized Vehicle/Equipment
Damage
Underground Gas Storage, Pressure Vessel, or Cavern
Allowed or Caused to Overpressure
Valve Left or Placed in Wrong Position, but NOT Resulting
in an Overpressure
1. Specify: Valve Misalignment
Incorrect Reference
Data/Calculation
Miscommunication
Inadequate Monitoring
Other ____________________________________
Pipeline or Equipment Overpressured
Equipment Not Installed Properly
Wrong Equipment Specified or Installed
Other Incorrect Operation
2. Describe:
__________________________________________________
Complete the following if any Incorrect Operation sub-cause is selected.
3. Was this Incident related to: (select all that apply)
Inadequate procedure
No procedure established
Failure to follow procedure
Other: ______________________________________________________
4. What category type was the activity that caused the Incident:
Construction
Commissioning
Decommissioning
Right-of-Way activities
Routine maintenance
Other maintenance
Normal operating conditions
Non-routine operating conditions (abnormal operations or emergencies)
5. Was the task(s) that led to the Incident identified as a covered task in your Operator Qualification Program? Yes
No
5a. If Yes, were the individuals performing the task(s) qualified for the task(s)?
Yes, they were qualified for the task(s)
No, but they were performing the task(s) under the direction and observation of a qualified individual
No, they were not qualified for the task(s) nor were they performing the task(s) under the direction and observation of a qualified
individual
G8 – Other Incident Cause - only one sub-cause can be picked from shaded left-hand column
Miscellaneous
1. Describe: _____
_________________________________________
Unknown
2. Specify:
Form PHMSA F 7100.2 (rev 6-2023)
Investigation complete, cause of Incident unknown
Mandatory comment field:
________________________________________
Still under investigation, cause of Incident to be
determined*
(*Supplemental Report required)
Reproduction of this form is permitted
Page 18 of 22
PART J – INTEGRITY INSPECTIONS
Complete the following if the “Item Involved in Accident” (from PART C, Question 3) is Pipe or Weld and the “Cause” (from Part G) is:
Corrosion (any subCause in Part G1); or
Previous Damage due to Excavation Activity (subCause in Part G3); or
Previous Mechanical Damage NOT Related to Excavation (subCause in Part G4); or
Material Failure of Pipe or Weld (any subCause in Part G5)
J1. Have internal inspection tools collected data at the point of the Incident?
Yes No
J1a. If Yes, for each tool and technology used provide the information below for the most recent and previous tool runs:
Axial Magnetic Flux Leakage
Most recent run Year:
Most recent run Propulsion Method (select only one):
Free Swimming Tethered
Hard Spots Girth Weld Anomalies
Most recent run Attuned to Detect (select only one): Metal Loss
If Metal Loss, specify (select only one):
Other Describe:
High Resolution
Standard Resolution
Other Describe:
Previous run Year:
Previous run Propulsion Method (select only one):
Previous run Attuned to Detect (select only one):
If Metal Loss, specify (select only one):
Free Swimming Tethered
Metal Loss Hard Spots Girth Weld Anomalies
Other Describe:
High Resolution
Standard Resolution
Other Describe:
Circumferential/Transverse Wave Magnetic Flux Leakage
Most recent run Year:
Free Swimming Tethered
High Resolution Standard Resolution
Other Describe:
Most recent run Propulsion Method (select only one):
Most recent run Resolution (select only one):
Previous run Year:
Previous run Propulsion Method (select only one):
Previous run Resolution (select only one):
Free Swimming Tethered
High Resolution Standard Resolution
Other Describe:
Ultrasonic
Most recent run Year:
Free Swimming Tethered
Wall Measurement Crack
Other Describe:
Most recent run Propulsion Method (select only one):
Most recent run Attuned to (select only one)
If Attuned to Wall Measurement, most recent run Metal Loss Resolution (select only one):
Standard Resolution
Previous run Year:
Other Describe:
Previous run Propulsion Method (select only one):
Most recent run Attuned to (select only one)
Free Swimming Tethered
Wall Measurement Crack
Other Describe:
If Attuned to Wall Measurement, most recent run Metal Loss Resolution (select only one):
Standard Resolution
Form PHMSA F 7100.2 (rev 6-2023)
Other Describe:
Reproduction of this form is permitted
Page 19 of 22
Geometry/Deformation
Most recent run Year:
Free Swimming Tethered
High Resolution Standard Resolution
Most recent run Resolution (select only one):
Other Describe:
Most recent run Measurement Cups (select only one): Inside ILI Cups
No Cups
Most recent run Propulsion Method (select only one):
Previous run Year:
Free Swimming Tethered
High Resolution Standard Resolution
Other Describe:
Previous run Measurement Cups (select only one): Inside ILI Cups
No Cups
Previous run Propulsion Method (select only one):
Previous run Resolution (select only one):
Electromagnetic Acoustic Transducer (EMAT)
Most recent run Year:
Most recent run Propulsion Method (select only one):
Previous run Year:
Previous run Propulsion Method (select only one):
Free Swimming Tethered
Cathodic Protection Current Measurement (CPCM)
Most recent run Year:
Most recent run Propulsion Method (select only one):
Previous run Year:
Previous run Propulsion Method (select only one):
Free Swimming Tethered
Free Swimming Tethered
Free Swimming Tethered
Other, specify tool:
Most recent run Year:
Most recent run Propulsion Method (select only one):
Previous run Year:
Previous run Propulsion Method (select only one):
Free Swimming Tethered
Free Swimming Tethered
Answer J1b only when the cause is:
Previous Damage due to Excavation Activity (subCause in Part G3); or
Previous Mechanical Damage NOT Related to Excavation (subCause in Part G4)
J1b. Do you have reason to believe that the internal inspection was completed BEFORE the damage was sustained?
Yes No
J2. Has one or more hydrotest or other pressure test been conducted since original construction at the point of the Incident?
(initial post construction pressure test is NOT reported here)
Yes
No
Most recent year tested: /
/
/
/
/
Test pressure (psig): /
J3. Has Direct Assessment been conducted on the pipeline segment?
Yes, and an investigative dig was conducted at the point of the Accident
Yes, but the point of the Accident was not identified as a dig site
No
If Yes, J3a. For each type, indicate the year of the most recent assessment:
External Corrosion Direct Assessment (ECDA)
/
/
Internal Corrosion Direct Assessment (ICDA)
/
/
Stress Corrosion Cracking Direct Assessment (SCCDA)
/
/
Confirmatory Direct Assessment
/
/
Other, specify type:
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
Most recent year conducted:
Most recent year conducted:
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
J4. Has one or more non-destructive examination been conducted prior to the Incident at the point of the Incident since January 1, 2002?
Yes No
J4a. If Yes, for each examination conducted, select type of non-destructive examination and indicate most recent year the examination was
conducted:
Radiography
Guided Wave Ultrasonic
Handheld Ultrasonic Tool
Wet Magnetic Particle Test
Dry Magnetic Particle Test
Other, specify type _______________
Form PHMSA F 7100.2 (rev 6-2023)
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
Reproduction of this form is permitted
Page 20 of 22
PART K – CONTRIBUTING FACTORS
The Apparent Cause of the accident is contained in Part G. Do not report the Apparent Cause again in this Part K. If Contributing Factors were
identified, select all that apply below and explain each in the Narrative:
Pipe/Weld Failure
External Corrosion
External Corrosion, Galvanic
Design-related
External Corrosion, Atmospheric
Construction-related
External Corrosion, Stray Current Induced
Installation-related
External Corrosion, Microbiologically Induced
Fabrication-related
External Corrosion, Selective Seam
Original Manufacturing-related
Internal Corrosion
Internal Corrosion, Corrosive Commodity
Environmental Cracking-related, Stress Corrosion Cracking
Environmental Cracking-related, Sulfide Stress Cracking
Internal Corrosion, Water drop-out/Acid
Environmental Cracking-related, Hydrogen Stress Cracking
Internal Corrosion, Microbiological
Environmental Cracking-related, Hard Spot
Internal Corrosion, Erosion
Equipment Failure
Natural Forces
Earth Movement, NOT due to Heavy Rains/Floods
Malfunction of Control/Relief Equipment
Compressor or Compressor-related Equipment
Heavy Rains/Floods
Threaded Connection/Coupling Failure
Lightning
Non-threaded Connection Failure
Temperature
Defective or Loose Tubing or Fitting
High Winds
Failure of Equipment Body (except Compressor), Vessel Plate,
or other Material
Tree/Vegetation Root
Excavation Damage
Excavation Damage by Operator (First Party)
Incorrect Operation
Excavation Damage by Operator’s Contractor (Second Party)
Excavation Damage by Third Party
Damage by Operator or Operator’s Contractor NOT Excavation
and NOT Vehicle/Equipment Damage
Valve Left or Placed in Wrong Position, but NOT Resulting in
Overpressure
Previous Damage due to Excavation Activity
Other Outside Force
Nearby Industrial, Man-made, or Other Fire/Explosion
Damage by Car, Truck, or Other Motorized Vehicle/Equipment
NOT Engaged in Excavation
Damage by Boats, Barges, Drilling Rigs, or Other Adrift
Maritime Equipment
Routine or Normal Fishing or Other Maritime Activity NOT
Engaged in Excavation
Pipeline or Equipment Overpressured
Equipment Not Installed Properly
Wrong Equipment Specified or Installed
Inadequate Procedure
No procedure established
Failure to follow procedures
Electrical Arcing from Other Equipment or Facility
Previous Mechanical Damage NOT Related to Excavation
Intentional Damage
Other underground facilities buried within 12 inches of the
failure location
Form PHMSA F 7100.2 (rev 6-2023)
Reproduction of this form is permitted
Page 21 of 22
PART H – NARRATIVE DESCRIPTION OF THE INCIDENT
(Attach additional sheets as necessary)
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
PART I – PREPARER AND AUTHORIZED PERSON
Preparer's Name (type or print)
Preparer's Title (type or print)
Preparer’s Telephone Number
Preparer's E-mail Address
Local Contact Name: optional
Local Contact Email: optional
Preparer’s Facsimile Number
Local Contact Phone: optional
Authorized Signer Telephone Number
Authorized Signer-Name
Authorized Signer’s Title
Authorized Signer’s E-mail Address
Form PHMSA F 7100.2 (rev 6-2023)
Reproduction of this form is permitted
Page 22 of 22
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
GENERAL INSTRUCTIONS
Each operator of a gas transmission or certain gathering pipeline system shall file Form PHMSA F
7100.2 for an incident that meets the criteria in 49 CFR §191.3 as soon as practicable but not more
than 30 days after detection of the incident. Operators reporting an incident on Type A, B, or C gas
gathering use this form. Operators reporting an incident on Type R gas gathering use Form PHMSA
F 7100.2-2. Requirements for submitting reports are in §191.7 and §191.15.
The intentional and controlled release of gas for the purpose of maintenance or other routine
operating activities is not to be reported. Reports are required if the loss of gas unintentionally
released is 3 million cubic feet or more.
Special considerations apply when a pipeline failure or release occurs involving secondary ignition.
Secondary ignition is a fire where the origin of the fire is unrelated to the gas systems subject to
Parts 191 or 192, such as electrical fires, arson, etc., and includes events where fire or explosion
not originating from a pipeline system failure or release was the primary cause of the pipeline
system failure or release, such as a refinery fire that subsequently resulted in – but was not caused
by – a gas transmission or gas gathering pipeline system failure or release. An event caused by
secondary ignition is not to be reported unless a release of gas escaping from facilities subject to
regulation under Parts 191 or 192 results in one or more of the consequences as described in §191.3
under "Incident" (1). The determination of consequences from a pipeline incident caused by
secondary ignition, though, is an area of possible confusion when reporting incidents. PHMSA is
providing the following guidance for operators to use when secondary ignition is involved
(sometimes referred to as “Fire First” incidents):
• A pipeline incident attributed to secondary ignition is to be reported to PHMSA
if any fatalities or injuries are involved unless it can be established with
reasonable certainty that all of the casualties either preceded the pipeline system
failure or release, or would have occurred whether or not the pipeline system
failure or release occurred.
• A pipeline incident attributed to secondary ignition is NOT to be reported to
PHMSA if the only reportable criterion is unintentional loss of gas of 3 million
cubic feet or more as described in §191.3 under "Incident" (1)(iii).
• A pipeline incident attributed to secondary ignition is NOT to be reported to
PHMSA unless the damage to facilities subject to Parts 191 or 192 equals or
exceeds the property damage reporting threshold in effect on the date of the
incident.
These considerations apply to several pipeline incident cause categories as indicated in pertinent
sections of these instructions.
Form PHMSA F 7100.2 and these instructions can be found on
http://phmsa.dot.gov/pipeline/library/forms. The applicable documents are listed in the section
titled Accident/Incident/Annual Reporting Forms.
Page 1 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
ONLINE REPORTING REQUIREMENTS
Incident Reports must be submitted online through the PHMSA Portal at
https://portal.phmsa.dot.gov/portal, unless an alternate method is approved (see Alternate Reporting
Methods below). You will not be able to submit reports until you have met all of the Portal
registration requirements – see
https://portal.phmsa.dot.gov/PHMSAPortal2/staticContentRedesign/howto/PortalAccountCreatio
n.pdf
Completing these registration requirements could take several weeks. Plan ahead and register well
in advance of the report due date.
Use the following procedure for online reporting:
1. Go to the PHMSA Portal at https://portal.phmsa.dot.gov/portal
2. Enter PHMSA Portal Username and Password ; press enter
3. Select OPID; press “continue” button.
4. On the left side menu under “Incident/Accident (2010 to present)” select “ODES 2.0”
5. Under “Create Reports” on the left side of the screen, select “Gas Transmission and
Gathering” and proceed with entering your data.
6. Click “Submit” when finished with your data entry to have your report uploaded to
PHMSA’s database as an official submission of an Incident Report; or click “Save” which
doesn’t submit the report to PHMSA but stores it in a draft status to allow you to come
back to complete your data entry and report submission at a later time. Note: The “Save”
feature will allow you to start a report and save a draft of it which you can print out and/or
save as a PDF to email to colleagues in order to gather additional information and then
come back to accurately complete your data entry before submitting it to PHMSA.
7. Once you click “Submit”, the system will check if all applicable portions of the report have
been completed. If portions are incomplete, a listing of these portions will appear above
the row of Parts. If all applicable portions have been completed, the system will show your
Saved Incident/Accident Reports in the top portion of the screen and your Submitted
Incident/Accident Reports in the bottom portion of the screen. Note: To confirm that your
report was successfully submitted to PHMSA, look for it in the bottom portion of the screen
where you can also view a PDF of what you submitted.
Supplemental Report Filing – Follow Steps 1 through 4 above, and then double-click a submitted
report from the Submitted Incident/Accident Reports list. The report will default to a “Read Only”
mode that is pre-populated with the data you submitted previously. To create a supplemental report,
click on “Create Supplemental” found in the upper right corner of the screen. At this point, you
can amend your data and make an official submission of the report to PHMSA as either a
Supplemental Report or as a Supplemental Report plus Final Report (see “Specific Instructions, PART
Page 2 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
A, Report Type”), or you can use the “Save” feature to create a draft of your Supplemental Report to
be submitted at some future date.
Alternate Reporting Methods
Operators for whom electronic reporting imposes an undue burden and hardship may submit a
written request for an alternate reporting method. Operators must follow the requirements in
§191.7(d) to request an alternate reporting method and must comply with any conditions imposed
as part of PHMSA’s approval of an alternate reporting method.
RETRACTING A 30-DAY WRITTEN REPORT
An operator who reports an incident in accordance with §191.15 (oftentimes referred to as a 30-day
written report) and upon subsequent investigation determines that the event did not meet the criteria
in §191.3 may request that the report be retracted. Requests to retract a 30-day written report are
to be emailed to [email protected]. Requests are to include the following
information:
a. The Report ID (the unique 8-digit identifier assigned by PHMSA)
b. Operator name
c. PHMSA-issued OPID number
d. The number assigned by the National Response Center (NRC) when an
immediate notice was made in accordance with §191.5. If Supplemental Reports
were made to the NRC for the event, list all NRC report numbers associated with
the event.
e. Date of the event
f. Location of the event
g. A brief statement as to why the report should be retracted.
Note: PHMSA no longer requests that operators rescind erroneously reported “Immediate Notices”
filed with the NRC in accordance with §191.5 (oftentimes referred to as “Telephonic Reports”).
Page 3 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
SPECIAL INSTRUCTIONS
Certain data fields must be completed before an Original Report will be accepted. Your Original
Report will not be able to be submitted online until the required information has been provided,
although your partially completed form can be saved online so that you can return at a later time to
provide the missing information.
1. An entry should be made in each applicable space or check box, unless otherwise directed by
the section instructions.
2. If the data is unavailable, enter “Unknown” for text fields and leave numeric fields and fields
using check boxes or “radio” buttons blank.
3. Estimate data only if necessary. Provide an estimate in lieu of answering a question with
“Unknown” or leaving the field blank. Estimates should be based on best-available information
and reasonable effort.
4. For unknown or estimated data entries, the operator should file a Supplemental Report when
additional or more accurate information becomes available.
5. If the question is not applicable, enter “N/A” for text fields and leave numeric fields and fields
using check boxes or “radio” buttons blank. Do not enter zero unless this is the actual value
being submitted for the data in question.
6. If OTHER is checked for any answer to a question, include an explanation or description on
the line provided, making it clear why “Other” was the necessary selection.
7. Pay close attention to each question for the phrase:
a. (select all that apply)
b. (select only one)
If the phrase is not provided for a given question, then “select only one” should apply. “Select
only one” means that you should select the single, primary, or most applicable answer. DO
NOT SELECT MORE ANSWERS THAN REQUESTED. “Select all that apply” requires that
all applicable answers (one or more than one) be selected.
8. Date format = mm/dd/yy or for year = /yyyy/
9. Time format: All times are reported as a 24-hour clock:
Time format Examples:
a. (0000) = midnight = /0/0/0/0/
b. (0800) = 8:00 a.m. = /0/8/0/0/
c. (1200) = Noon
= /1/2/0/0/
d. (1715) = 5:15 p.m. = /1/7/1/5/
e. (2200) = 10:00 p.m. = /2/2/0/0/
Page 4 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
Local time always refers to time at the site of the incident. Note that time zones at the
incident site may be different than the time zone for the person discovering or reporting the
event. For example, if a release occurs at an gas transmission facility in Denver, Colorado
at 2:00 pm MST, but an individual located in Houston is filing the report after having been
notified at 3:00 pm CST, the time of the incident is to be reported as 1400 hours based on
the time in Denver, which is the physical site of the incident.
PART A – KEY REPORT INFORMATION
Report Type: (select all that apply)
Select the appropriate report box or boxes to indicate the type of report being filed. Depending on
the descriptions below, the following combinations of boxes – and only one of these combinations
- may be selected:
• Original Report only
• Original Report plus Final Report
• Supplemental Report only
• Supplemental Report plus Final Report
Original Report
Select if this is the FIRST report filed for this incident and you expect that additional or updated
information will be provided later.
Original Report
plus
Final Report
Select both Original Report and Final Report if ALL of the information requested is known and
can be provided at the time the initial report is filed, including final property damage costs and
apparent failure cause information. If new, updated, and/or corrected information becomes
available, you are still able to file a Supplemental Report.
Supplemental Report
Select only if you have already filed an Original Report AND you are now providing new, updated,
and/or corrected information. Multiple Supplemental Reports are to be submitted, as necessary, in
order to provide new, updated, and/or corrected information when it becomes available and, per
§191.15(c), each Supplemental Report containing new, updated, and/or corrected information is to
be filed as soon as practicable. Submission of new, updated, and/or corrected information is NOT
to be delayed in order to accumulate “enough” to “warrant” a Supplemental Report, or to complete
a Final Report. Supplemental Reports must be filed as soon as practicable following the
Operator’s awareness of new, updated, and/or corrected information. Failure to comply with
these requirements can result in enforcement actions, including the assessment of civil penalties as
provided in 49 USC 60122.
Page 5 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
For Supplemental Reports filed online, all data previously submitted will automatically populate in
the form. Page through the form to make edits and additions where needed.
Supplemental Report
plus
Final Report
If an Original Report has already been filed AND new, updated, and/or corrected information is
now being submitted via a Supplemental Report AND the operator is reasonably certain that no
further information will be forthcoming, then Final Report is to also be selected along with
Supplemental Report. If you subsequently find that new, updated, and/or corrected information
needs to be provided, submit another Supplemental Report.
A1. Operator’s OPS -Issued Operator Identification Number (OPID)
For online entries, the OPID will automatically populate based on the selection you made when
entering the Portal. If you have log-in credentials for multiple OPID, be sure the report is being
created for the appropriate OPID. Contact PHMSA’s Information Resources Manager at 202-3668075 if you need assistance with an OPID. Business hours are 8:30 AM to 5:00 PM Eastern Time.
A2. Name of Operator
This is the company name associated with the OPID. For online entries, the name will
automatically populate based on the OPID entered in A1. If the name that appears is not correct,
you need to submit an Operator Name Change (Type A) Notification.
A3. Address of Operator
For online entries, the headquarters address will automatically populate based on the OPID entered
in A1. If the address that appears is not correct, you need to change it in the online Contacts module.
A4. Local time (24-hour clock) and date of incident
Enter the earliest of the following:
estimate of the time/date when the release of commodity began; or
time/date that personal injury or damage to property first occurred rather than the
time/date the consequences are quantified; or
for the underground natural gas storage facility emergency shutdown criteria, the
time/date of the shutdown.
In most cases, this time/date will be nearly the same as when the operator identified the failure,
which is reported in A13. In some cases, this date/time will be prior to the operator’s
identification of the failure and must be estimated based on information gathered during the
investigation. For example, the operator will need to estimate the time/date that the release began
for large leaks that are not detected remotely and do not impact people or property.
See “Special Instructions”, numbers 8 and 9 for examples of Date format and Time format
expressed as a 24-hour clock.
Page 6 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
A4a. Select the local time zone where the Incident occurred (select only one).
A4b. Select “Yes” if Daylight Saving was in effect at the time of the Incident, or “No” if
it was not.
Page 7 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
A5. Location of Incident
The latitude and longitude of the incident are to be reported as Decimal Degrees with a minimum
of 5 decimal places (e.g. Lat: 38.89664 Long: -77.04327), using the NAD83 or WGS84 datums.
If you have coordinates in degrees/minutes or degrees/minutes/seconds, use the formula below to
convert to decimal degrees:
degrees + (minutes/60) + (seconds/3600) = decimal degrees
e.g. 38° 53' 47.904" = 38 + (53/60) + (47.904/3600) = 38.89664°
All locations in the United States will have a negative longitude coordinate, which has already
been included on the data entry form so that operators do not have to enter the negative sign.
If you cannot locate the incident with a GPS or some other means, there are online tools that may
assist you at http://viewer.nationalmap.gov/viewer/. Any questions regarding the required format,
conversion, or how to use the tools noted above can be directed to Amy Nelson (202-493-0591 or
[email protected]).
A6. Gas released
Select the type of gas released. An example of Synthetic Gas is manufactured gas based on
naphtha. Landfill Gas includes biogas.
Important Note for Questions 7, 8, and 9: Volumes consumed by fire and/or explosion are to be
included in the estimated volumes reported.
A7. Estimated volume of gas released unintentionally
Estimate the amount of gas that was released (in thousands of standard cubic feet, mcf) from the
beginning of the incident until such time as gas is no longer being released from the pipeline system
or until intentional and controlled blowdown has commenced. Estimates are to be based on bestavailable information. Important Note: Volumes consumed by fire and/or explosion are to be
included in the estimated volume reported.
The volumes released during an Emergency Shutdown (ESDs) or relief valve activation should be
reported. When ESDs or relief valves are activated as the result of a safety condition that has
occurred, the volume released should be included in the “unintentional” category, even if safety
equipment performed as designed (such as a power loss or upon a PLC command). This would
include when an employee intentionally activates the ESD in response to an unintentional safety
condition, such as a grass fire in the station yard.
A8. Estimated volume of intentional and controlled release/blowdown
Estimate the amount of gas that was released (in thousands of standard cubic feet, mcf) during any
intentional release or controlled blowdown conducted as part of responding to or recovering from
Page 8 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
the incident. Intentional and controlled blowdown implies a level of control of the site and situation
by the operator such that the area and the public are protected during the controlled release.
Occasionally actions associated with response to an incident can involve activation of the
Emergency Shutdown (ESD) and associated relief equipment that occurs on a planned maintenance
basis after the incident initial safety response and the area has been evaluated for damage. For
example, an engine crankcase explosion has occurred and only one compressor in the area is
damaged. The immediate unintentional release was to activate the blowdown equipment associated
with this engine only. However, upon reviewing the damage, it was determined that the ESD
system should be activated for an entire station as more than one engine’s systems were affected
by the incident. The volume of intentional ESD release or associated relief devices that has
occurred after the evaluation in anticipation for the repairs should be included in the “intentional”
volume released.
A9. Estimated volume of accompanying liquid released
Estimate the amount of accompanying liquid that was spilled to the ground (or other containment)
as a liquid (in barrels) from the beginning of the incident until such time as the liquid is no longer
being released from the system. Barrel means a unit of measurement equal to 42 U.S. standard
gallons. If less than 1 barrel, report to 1 decimal place using the conversion table below. Small
volumes, including but not limited to those which sometimes result in some form of ignition, are to
be reported as 0.1 barrels.
If estimated volume
is
<5
5-10
11-14
15-18
19-23
gallons
gallons
gallons
gallons
gallons
Report
0.1
0.2
0.3
0.4
0.5
barrels
barrels
barrels
barrels
barrels
If estimated volume
is
24-27
28-31
32-35
36-39
40-42
gallons
gallons
gallons
gallons
gallons
Report
0.6
0.7
0.8
0.9
1.0
barrels
barrels
barrels
barrels
barrels
A10. Were there fatalities?
If a person dies at the time of the incident or within 30 days of the initial incident date due to injuries
sustained as a result of the incident, report as a fatality. If a person dies subsequent to an injury
more than 30 days past the incident date, report as an injury. (Note: This aligns with the
Department of Transportation's general guidelines for all jurisdictional transportation modes for
reporting deaths and injuries.)
Select “Yes” or “No” and if “Yes” is selected, enter the category of person(s) and number of
fatalities resulting from the Incident.
Contractor employees working for the operator are individuals hired to work for or on behalf of
the operator of the pipeline. These individuals are not to be reported as “Operator employees”.
Page 9 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
Non-Operator emergency responders are individuals responding to render professional aid at the
incident scene, including on-duty and volunteer fire fighters, rescue workers, EMTs, police officers,
etc. “Good Samaritans” that stop to assist are to be reported as “General public.”
Workers Working on the Right-of-Way, but NOT Associated with this Operator means people
authorized to work in or near the right-of-way, but not hired by or working on behalf of the
operator of the pipeline. This includes all work conducted within the right-of-way including
work associated with other underground facilities sharing the right-of-way, building/road
construction in or across the right-of-way, or farming. This category most often includes
employees of other pipelines or underground facilities operators, or their contractors, working
in or near a shared right-of-way. Workers performing work near, but not on, the right-of-way
and who are affected are to be reported as “General public”.
A11. Were there injuries requiring inpatient hospitalization?
Injuries requiring inpatient hospitalization are injuries sustained as a result of the incident and that
require both hospital admission and at least one overnight stay.
Select “Yes” or “No” and if “Yes” is selected, enter the category of person(s) and number of
fatalities resulting from the Incident.
See Question A10 for additional definitions that apply.
A12. What was the Operator’s initial indication of the Failure? (select only one)
Select the best option to describe the manner in which the operator initially identified the failure
resulting in this reported Incident.
Controller means a qualified individual whose function within a shift is to remotely monitor and/or
control the operations of entire or multiple sections of pipeline systems via a SCADA system from
a pipeline control room, and who has operational authority and accountability for the daily remote
operational functions of pipeline systems.
Local Operating Personnel including contractors means employees or contractors working on
behalf of the operator outside the control room.
A12a. If the Incident was identified by Operator’s personnel or a contractor working for the
Operator (including controller, air and ground patrols) in A12, identify if it was by an Operator
employee, or a contractor working for the Operator.
A13. When did the operator identify the failure?
Enter the date/time of the operator’s initial indication of the failure reported in A12.
A14. What part of the system was involved in the Incident?
Select the best description of the part of the system that was involved in the Incident. Only one
selection may be made.
Page 10 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
A15. What was the operational status of the pipeline at the time the failure was identified?
Select the best description of the operating status of the pipeline system at the date/time reported
in A4.
Post-Construction Commissioning means the introduction of product, testing and
commissioning of the pipeline prior to the start of commercial operations.
Post-Maintenance/Repair means purging and packing of the pipeline when returning it to
service from maintenance or repairs.
Routine Start-Up means the start-up of the pipeline, facility or system in normal operations, or
returning from maintenance or other idle status following a time of no flow, but the where the
pipeline remained liquid full, and the start-up was being conducted under normal start-up
procedures.
Routine Shutdown means the stoppage of equipment or the system from a normal operation
status.
Normal Operation, include pauses during maintenance means the pipeline is operating
normally, and any of the maintenance that is occurring does not require product to be removed
from the pipeline or system. Product sampling, inhibitor injection, in-line inspection, installation
of repairs, and other activities covered by the operator’s Operation and Maintenance Procedures
are examples of the maintenance included in this category.
Idle means that the pipeline has been removed from service for commercial reasons or to make
repairs. The pipeline may contain product, an inert gas, or be empty. When residual product
accumulates in an excavation and ignites, Idle is the proper status.
A16. Was the pipeline/facility shut down due to the Incident?
If A15. is Routine Start-Up or Normal Operations, indicate if shutdown occurred as a result of the
incident, including but not limited to those required for damage assessment, temporary repair,
permanent repair, and clean-up. Do not include equipment shutdowns that do not affect the pipeline
or system operation. For example, if a compressor shutdown occurred as part of the incident, but
the pipeline was able to continue operating, select No. If No is selected, explain the reason that no
shutdown was needed in the space provided. A possible explanation for the example above would
be “The pipeline continued to operate through the station bypass piping and did not require a
pipeline shutdown.”
If Yes is selected, complete Questions 16a and 16b.
16a. Local time (24hr clock) and date of shutdown
16b. Local time pipeline/facility restarted
Page 11 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
The time is to be shown by 24-hour clock notation, and is to reflect the time in the time zone where
the incident was physically located. (See “Special Instructions”, numbers 9 and 10.) Enter the time
and date the pipeline was isolated or equipment stopped in 16a. The affected facilities may still
contain gas at this time. Enter the time and date of restart in 16b. The intent with this data is to
capture the total time that the pipeline or facility is shutdown due to the incident. If the pipeline or
facility has not been restarted, select “Still shut down” for Question 15b and then include the restart
time and date in a future Supplemental Report.
A17. Operator Communication with Local, State, or Federal Emergency Responders
In an Advisory Bulletin dated October 11, 2012, PHMSA reminded Operators of the need to
communicate with Emergency Responders in the early stages of a potential Incident. This is
typically accomplished by contacting Public Safety Access Points (PSAPs) along the pipeline route.
The purpose of the communication is to assist in the identification, location, and planning for
response to pipeline Incidents through coordination and information sharing.
A17a. Select Yes if there was communication about the incident. If A12. is “Notification from
Emergency Responder”, A17a. will automatically populate with Yes.
If 17a. is no, skip 17b. and 17c.
A17b. Select the party initiating the communication. If A12. is “Notification from Emergency
Responder”, A17b. will automatically populate with “Local/State/Federal Emergency
Responder”.
A17c. Enter the local date and time of the initial communication. If A12. is “Notification from
Emergency Responder”, A17c. will automatically populate with the value in A13.
A18. What time did Operator resources arrive on site?
Enter the date/time operator responders, company or contract, arrived on site. The time is to be
shown by 24-hour clock notation and reported in the time zone where the incident occurred. (See
“Special Instructions”, numbers 8 and 9.) PHMSA will use this data to calculate incident response
times.
A19. Enter local time and date of Confirmed Discovery as defined in 49 CFR §191.3
A20a. Local time (24-hr clock) and date of initial operator report to the National Response
Center
Enter the time and date of the initial Immediate Notice of the incident to the NRC. The time is to
be shown by 24-hour clock notation in the time zone where the incident occurred. All NRC reports
are time stamped for the eastern time zone. Be sure to convert to local time if the incident did not
occur in the eastern time zone. (See “Special Instructions”, numbers 9 and 10.)
A20b. Initial Operator National Response Center (NRC) Report Number
§191.5 requires that incidents meeting the criteria outlined in §191.3 be reported directly to the 24-
Page 12 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
hour National Response Center (NRC) at 1-800-424-8802 at the earliest practicable moment .
The NRC assigns numbers to each call. Enter the number assigned to the operator’s initial
Immediate Notice (sometimes referred to as the “Telephonic Report”). If a NRC report was not
made, select the option that best describes why: NRC Notification Not Required, NRC Notification
Required But Not Made, Do Not Know NRC Report Number.
A20c. Additional NRC Report Numbers
If the operator made more than one call to the NRC, enter each additional NRC report number.
A21. Did the gas ignite?
Ignite means the released gas caught fire, or a conflagration, detonation or explosion occurred,
even if there was no residual fire after the initial ignition event. If the answer is “Yes,” enter the
time and date of the ignition in 21a. The time is to be shown by 24-hour clock notation in the time
zone where the Incident occurred. If the fire was extinguished, select “Operator/Contractor” or
“Local/State/Federal Emergency Responder,” to indicate who extinguished the fire, or select
“Allowed to Burn Out,” if it was not extinguished, in 21b. Enter the estimated volume of gas
consumed by fire in thousands of standard cubic feet, MCF in 21c.
A21d. Did the gas explode?
Explode means the ignition of the released gas occurred with a sudden and violent release of
energy.
A22. Flow Control
If A14. is “Onshore Pipeline, Including Valve Sites” OR “Offshore Pipeline, Including Riser and
Riser Bend”, answer A22.
The initial response to gas pipeline emergencies is typically understood to be isolation of the
incident location from the source of gas. However, sometimes there are operational means other
than valve closures to achieve this goal. These questions are intended to understand the response
actions and the time of valve closures intended to isolate the incident location. Valve data is for
the first upstream or downstream valve selected by the operator to minimize the release volume but
may not be the closest to the incident site or the one that was eventually used for the final isolation
of the release site for repair.
Upstream of Failure - If an action other than valve closure was taken to isolate the incident site
from the upstream pipeline, select “Operational Control” for 22a and provide a description of the
operation control employed.
If 22a. is “Valve Closure”, complete 22b. and 22c.
A22b. Enter the time of the valve closure that achieved isolation of the incident location from
upstream piping.
A22c. Identify the type of valve used to initially isolate the release on the upstream side.
Page 13 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
Downstream of Failure - If an action other than valve closure was taken to isolate the incident site
from the downstream pipeline, select “Operational Control” for 22d. and provide a description of
the operation control employed.
If 22d. is “Valve Closure”, complete 22e. and 22f.
A22e. Enter the time of the valve closure that achieved isolation of the incident location from
downstream piping.
A22f. Identify the type of valve used to initially isolate the release on the downstream side.
A23. Number of general public evacuated
The number of people evacuated is to be estimated based on operator knowledge, or police, fire
department, or other emergency responder reports. If there was no evacuation involving the general
public, report zero (0).
Page 14 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
PART B – ADDITIONAL LOCATION INFORMATION
B1. Was the origin of the incident onshore?
Populated automatically based on response to A14.
B1a. Pipeline/Facility name
Multiple pipeline systems and/or facilities are often operated by a single operator. This information
identifies the particular pipeline system or pipeline facility name commonly used by the operator
on which the incident occurred, for example, the “West Line 24” Pipeline”, or “Gulf Coast
Pipeline”, or “Wooster Storage Facility”.
B1b. Segment name/ID
Within a given pipeline system and/or facility, there are typically multiple segment or station
identifiers, names, or ID’s which are commonly used by the operator. The information to be
reported here helps locate and/or record the more precise incident location, for example, “Segment
4-32”, or “MP 4.5 to Wayne County Line”, or “Dublin Compressor Station”, or “Witte Reducing
Station”. Consideration should be given to using the same pipeline segment name that was
submitted to NPMS, where appropriate.
If Onshore
B2. – B5. Incident Location
Provide the state, zip code, city, and county/parish in which the incident occurred. If the incident
did not occur within a municipality, select Not Within Municipality in the City field. If the incident
did not occur within county/parish, select Not Within County/Parish.
B6. and B7. Operator-designated location
This is intended to be the designation that the operator would use to identify the location of the
incident on its pipeline system. Enter the appropriate milepost or survey station number. This
designator is intended to allow PHMSA personnel to refer to the physical location of the incident
using the operator’s maps and records.
B8. Was the Incident on Federal Lands other than the Outer Continental Shelf?
Federal Lands other than Outer Continental Shelf means all lands the United States owns, including
military reservations, except lands in National Parks and lands held in trust for Native Americans.
Incidents at Federal buildings, such as Federal Court Houses, Custom Houses, and other Federal
office buildings and warehouses, are NOT to be reported as being on Federal Lands.
Page 15 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
B9. Location of Incident
Operator-controlled Property would normally apply to an operator’s facility, which may or may
not have controlled access, but which is often fenced or otherwise marked with discernible
boundaries. This “operator-controlled property” does not refer to the pipeline right-of-way, which
is a separate choice for this question.
B10. Area of Incident (as found)
This refers to the location on the pipeline system at which gas was released, resulting in the incident.
It does not refer to adjacent locations in which released gas may have accumulated or ignited.
Underground means pipe, components, or other facilities installed below the natural ground level,
road bed, or below the underwater natural bottom.
Under pavement includes under streets, sidewalks, paved roads, driveways, and parking lots.
Exposed due to Excavation means that a normally buried pipeline had been exposed by any party
(operator, operator’s contractor, or third party) preparatory to or as a result of excavation. The
cause of the release, however, may or may not necessarily be related to excavation damage. This
category could include a corrosion leak not previously evidenced by dead vegetation, but found
during an ILI dig, or a release caused by a non-excavation vehicle where contact happened to occur
while the pipeline was exposed for a repair or examination. Natural forces might also damage a
pipeline that happened to be temporarily exposed. In each case, the cause is to be appropriately
reported in PART G of this form.
Exposed due to loss of cover means that erosion, flooding, or some other non-excavation action
has removed the cover that was previously over the pipeline. This loss of cover may be previously
known or unknown by the pipeline operator, but to be reported in this category, the pipeline was
believed to have been exposed prior to the Incident. Loss of cover as a result of the Incident
should not be reported under this category. For example – if a pipeline was buried below
ground immediately prior to a failure, and the force of the failure unearthed the pipeline – it should
still be reported as “Under soil,” for the purposes of this report.
Aboveground means pipe, components, or other facilities that are above the natural grade.
Typical aboveground facility piping includes any pipe or components installed aboveground such
as those at compressor stations, valve sites, launcher and receiver and reducing stations.
Transition area means the junction of differing material or media between pipes, components, or
facilities such as those installed at a belowground-aboveground junction (soil/air interface), another
environmental interface, or in close contact to supporting elements such as those at water crossings,
compressor stations, and gas storage facilities.
If B10. is Underground, answer 10a. and 10b:
B10a. Depth of Cover
Page 16 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
Report the depth of cover in inches immediately before the incident. In cases where the incident
changed the depth of cover, the depth prior to the incident will be an estimate.
B10b. Indicate if other underground facilities were found within 12 inches of the failure location.
B11. Did Incident occur in a crossing?
Use Bridge Crossing if the pipeline is suspended above a body of water or roadway, railroad rightof-way, etc. either on a separately designed pipeline bridge or as a part of or connected to a road,
railroad, or passenger bridge.
Use Railroad Crossing or Road Crossing, as appropriate, if the pipeline is buried beneath rail bed
or road bed.
Use Water Crossing if the pipeline is in the water, beneath the water, in contact with the natural
ground of the lake bed, etc., or buried beneath the bed of a lake, reservoir, stream or creek, whether
the crossing happens to be flowing water at the time of the incident or not. The name of the body
of water is to be provided if it is commonly known and understood among the local population.
(The purpose of this information is to allow persons familiar with the area in which the incident
occurred to identify the location and understand it in its local context. Research to identify names
that are not commonly used is not necessary since such names would not fulfill the intended
purpose. If a body of water does not have a name that is commonly used and understood in the
local area, this field may be left blank).
For Approximate water depth (ft) of the lake, reservoir, etc., estimate the typical water depth at
the location and time of the incident, ignoring seasonal, weather-related, and other factors which
may affect the water depth from time to time.
If B11 is yes, indicate whether the pipe is cased.
If a water crossing, specify the pipe installation method and answer the question about the
length of the crossing.
If Offshore
B12. Approximate water depth (ft.) at the point of the Incident
This is to be the estimated depth from the surface of the water to the seabed at the point of the
incident regardless of whether the pipeline is below/on the bottom, underwater but suspended above
the bottom, or above the surface (e.g., on a platform).
B13. Origin of the Incident
Area and Tract/Block numbers are to be provided for either State or OCS waters, whichever is
applicable.
Page 17 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
For Nearest County/Parish, as with the name of an onshore body of water (see Question 12 above),
the data collected is intended to allow persons familiar with the area in which the incident occurred
to identify the location and understand it in its local context. Accordingly, it is not necessary to
take measurements to determine which county/parish is precisely “nearest” in cases where the
incident location is approximately equidistant from two (or more). In such cases, the name of one
of the nearby counties/parishes is to be provided.
For Incidents on the Outer Continental Shelf (OCS), identify the region where the Incident occurred
by selecting one of the four options listed.
B15. Area of the Incident
For all Offshore Incidents, specify the area of the Incident by selecting the best description of the
location where the Incident occurred.
PART C – ADDITIONAL FACILITY INFORMATION
C1. Is the pipeline or facility [Interstate or Intrastate]?
Interstate gas pipeline facility means a gas pipeline facility or that part of a gas pipeline facility
that is used to transport gas and is subject to the jurisdiction of the Federal Energy Regulatory
Commission (FERC) under the Natural Gas Act (15 U.S.C. 717 et seq.).
Intrastate gas pipeline facility means a gas pipeline facility or that part of a gas pipeline facility
that is used to transport gas within a state and is not subject to the jurisdiction of FERC under the
Natural Gas Act (15 U.S.C. 717 et seq.).
The reported jurisdiction should match both the Annual Report and NPMS submittals for the
pipeline, if applicable.
C2. Material involved in Incident
Enter the material involved in the Incident. If the material is other than Carbon Steel or Plastic,
select “Material other than Carbon Steel or Plastic” and specify the type of material in the space
provided.
C3. Item involved in Incident
Pipe (whether pipe body or pipe seam) means the pipe through which product is transported, not
including auxiliary piping, tubing, or instrumentation.
Nominal Pipe Size. It is the diameter in whole number inches (except for pipe less than 5”) used
to describe the pipe size; for example, 8-5/8” pipe has a nominal pipe size of 8. Decimals are
unnecessary for this measure (except for pipe less than 5”). For more details, see
http://en.wikipedia.org/wiki/Nominal_Pipe_Size
Enter pipe wall thickness in inches. Wall thickness is typically less than an inch. Accordingly,
use three decimal places to report wall thickness: 0.312, 0.281, etc.
Page 18 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
SMYS means specified minimum yield strength and is the yield strength prescribed by the
specification under which the material is purchased from the manufacturer. If the SMYS is
unknown, and the Operator has designated it as 24,000 for the purposes of MAOP calculations,
enter 24,000.
Pipe Specification is the specification to which the pipe was manufactured, such as API 5L or
ASTM A106.
Pipe seam means the longitudinal seam (longitudinal weld) created during manufacture of the joint
of pipe.
Pipe Seam Type Abbreviations
SAW means submerged arc weld
ERW means electric-resistance weld
DSAW means double submerged arc weld
If the frequency of the ERW pipe seam is unknown, and the pipe was manufactured after 1980,
select Longitudinal ERW – High Frequency. Almost all ERW pipe manufactured prior to 1960 is
Low Frequency, and both High and Low Frequency ERW pipe was manufactured between 1960
and 1980.
If differences exist between pipe on either side of a Girth Weld Failure, Populate C3l. through C3r.
as needed.
If the incident occurred on an item not provided in this section, select “Other” and specify the
item that failed in the space provided. Make every effort to find an item category and avoid
the use of “Other” when reporting the Type of Item involved in the Incident.
C4. Year Installed Enter the year the item that failed was installed.
C5. Year Manufactured If you know the year the item that failed was manufactured, enter it.
Otherwise, select Unknown.
C6. Type of release involved (select only one)
Mechanical puncture means a puncture of the pipeline, typically by a piece of equipment such as
would occur if the pipeline were pierced by directional drilling or a backhoe bucket tooth. Not all
excavation-related damage will be a “mechanical puncture.” (Precise measurement of size – e.g.,
using a micrometer – is not needed. Approximate measurements can be provided in inches and one
decimal.)
Leak means a failure resulting in an unintentional release of gas that is often small in size, usually
resulting in a low flow release of low volume, although large volume leaks can and do occur on
occasion. A leak may be a hole or a crack, and includes separation of materials, pullout and loose
connections. Typically, a Leak can be repaired, whereas a Rupture results in the complete failure
of the pipeline.
Page 19 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
Rupture means the pipeline facility has burst, split, or broken and the operation of the pipeline
facility is immediately impaired and no longer serviceable. The terms “circumferential” and
“longitudinal” refer to the general direction or orientation of the rupture relative to the pipe’s axis.
For example; a rupture of a girth weld would be circumferential, whereas a split that followed the
length of the pipe (whether in the seam, or not) would be longitudinal. (Precise measurement of
size – e.g., micrometer – is not needed. Approximate measurements can be provided in inches and
decimals.)
PART D – ADDITIONAL CONSEQUENCE INFORMATION
See 49 CFR § 192.903 for “high consequence area” definition.
D1. Select the Class Location at the point of the failure.
D2. Did this Incident occur in a High Consequence Area (HCA)?
This question is to be answered based on the classification of the involved segment in the operator’s
Integrity Management (IM) Program at the time of the incident.
D2a. Specify the Method used to identify the HCA:
Answer this question only if the incident occurred in an HCA.
As defined in §192.903, HCAs are determined by one of two methods: Method (1) uses class
locations, and Method (2) uses potential impact circles. The operator is to identify the method used
within its IM program to determine that the location at which the incident occurred was an HCA.
D3. What is the PIR (Potential Impact Radius) for the location of this Incident?
An operator is to answer this question for all incidents, regardless of whether or not the incident
occurred in a high consequence area (HCA) or of the method used to identify an HCA. A PIR is
one of the two methods for identifying an HCA, and this question and those immediately following
are intended to collect data from actual incidents as part of a continuing effort to assure that the
definition of a PIR is appropriate for that purpose. If the Incident involved the release of a nonflammable gas, select “Not Flammable.”
PIR is defined in §192.903 as the radius of a circle within which the potential failure of a pipeline
could have significant impact on people or property. PIR is determined by the formula:
________
r = 0.69 * √ p * d2
where: r is the radius of a circular area in feet surrounding the point of failure,
p is the maximum allowable operating pressure (MAOP) in the pipeline
segment in pounds per square inch and
d is the nominal diameter of the pipeline in inches.
Page 20 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
[0.69 is the factor for natural gas. This number will vary for other gases depending upon their heat
of combustion. An operator transporting gas other than natural gas must use Section 3.2 of
ASME/ANSI B31.8S-2001 (Supplement to ASME B31.8; incorporated into the regulations by
reference, see §192.7) to calculate the impact radius formula.]
D4. Were any structures outside the PIR impacted or otherwise damaged by heat/fire
resulting from the Incident?
Report any damage to structures further from the point of failure than the PIR distance that resulted
from heat radiation or fires started as a result of the incident.
D5. Were any structures outside the PIR impacted or otherwise damaged NOT due to
heat/fire resulting from the Incident?
This would include damage by blast effects, impact from flying debris dislodged by a pipeline
rupture, etc.
D6. Were any of the fatalities or injuries reported for persons located outside the PIR?
This refers only to the injuries reported in A11. Do not consider less severe injuries reported in D8.
and D9. The description of the cause of the fatality or injury should be general in nature. For
example; burns, struck by flying debris, smoke inhalation, crushed by falling object, are examples
of causes that could be used to describe the apparent physical cause of the injury or fatality outside
the PIR.
Moderate consequence area (MCA) is defined in 49 CFR Part 192.
D13a. Did the incident occur in an MCA? If yes, complete D13b. by selecting all that were
present within the potential impact radius.
D7. Estimated Property Damage
All relevant costs available at the time of submission must be included on the initial written Incident
Report as well as being updated as needed on Supplemental Reports. This includes (but is not
limited to) costs due to property damage to the operator’s facilities and to the property of others,
facility repair and replacement, and environmental cleanup and damage. Do NOT include cost of
gas lost. Additionally, do NOT include costs incurred for facility repair, replacement, or changes
that are NOT related to the incident and which are typically done solely for convenience. An
example of doing work solely for convenience is working on non-leaking facilities unearthed
because of the incident. Litigation and other legal expenses related to the incident are not
reportable.
Operators are to report costs based on the best estimate available at the time a report is submitted.
It is likely that an estimate of final repair costs may not be available when the initial report must be
submitted (within 30 days, per §191.15). The best available estimate of these costs is to be included
in the initial report. For convenience, this estimate can be revised, if needed, when Supplemental
Page 21 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
Reports are filed for other reasons, however, when no other changes are forthcoming, Supplemental
Reports are to be filed as new cost information becomes available. If Supplemental Reports are not
submitted for other reasons, a Supplemental Report is to be filed for the purpose of updating or
correcting the estimated cost if these costs differ from those already reported by 20 percent or
$20,000, whichever is greater.
D7a. Public and Non-operator private property damage estimates generally include physical
damage to the property of others, the cost of investigation and remediation of a site not owned or
operated by the operator, laboratory costs, third party expenses such as engineers or scientists, and
other reasonable costs, excluding litigation and other legal expenses related to the incident.
D7b. Operator’s property damage & repairs estimates generally include physical damage to the
property of the operator or owner company such as the estimated installed or replacement value of
the damaged pipe, coating, component, materials, or equipment due to the incident, excluding the
cost of any gas lost. Also to be excluded are litigation and other legal expenses related to the
incident.
When estimating the Cost of repairs to company facilities, the standard shall be the cost necessary
to safely restore property to its predefined level of service. Property damage estimates include the
cost to access, secure, excavate, and repair the pipeline using methods, materials, and labor
necessary to re-establish operations at a predetermined level. These costs may include the cost of
repair sleeves or clamps, re-routing of piping, or the removal from service of an appurtenance or
pipeline component. When more comprehensive repairs or improvements are justified but not
required for continued operation, the cost of such repairs or replacement is not attributable to the
incident. Costs associated with improvements to the pipeline or other facilities to mitigate the risk
of future failures are not included.
D7c. Emergency response includes emergency response operations necessary to return the
incident site to a safe state, actions to minimize the volume of gas released, conduct reconnaissance,
and to identify the extent of incident impacts. They include materials, supplies, labor, and benefits.
If you reimbursed local, state, or federal emergency responders, include these amounts. Costs
related to stakeholder outreach, media response, etc. are not to be included.
D7d. Other costs are to include any and all costs which are not included above. Cost of any gas
lost is NOT to be reported here, but is to be reported under Cost of Gas Released. Operators are
to NOT use this category to report any costs which belong in cost categories separately listed above.
Costs are to be reported in only one category and are not to be double-counted. Costs can be split
between two or more categories when they overlap more than one reporting category.
Cost of Gas Released – enter your gas cost, excluding taxes, in dollars per thousand standard cubic
feet (mcf). The cost of gas released will be calculated based on the volumes reported in A7 and
A8.
Page 22 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
Injured persons not included in A11. The number of persons injured, admitted to a hospital,
and remaining in the hospital for at least one overnight are reported in A11. If a person is
included in A11, do not include them in D8.
D8. Estimated number of persons with injuries requiring treatment in a medical facility but not
requiring overnight in-patient hospitalization.
If a person is included in D8, do not include them in D9.
D9. Estimated number of persons with injuries requiring treatment by EMTs at the site of incident.
Buildings Affected The term ‘affected’ means the building was either damaged, or evacuated,
or had gas service interrupted.
D10. Enter the number of residential buildings affected.
D11. Enter the number of commercial and industrial buildings affected.
D12. If wildlife was impacted, select Yes and indicate the type in D12a. Otherwise, select No.
Page 23 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
PART E – ADDITIONAL OPERATING INFORMATION
E1. Estimated Pressure and Flow Rate
Enter the estimated operating pressure, in psig, at the location and time of the incident.
Enter the estimated flow rate in the pipeline segment at the location and time of the Incident.
E2. Maximum Allowable Operating Pressure (MAOP)
Enter the MAOP, in psig, at the point and time of the Incident.
E2a. MAOP Established By
Select the response that describes the basis for establishing the MAOP at the incident site. A
short explanation of each 192.619 option and “Other” is:
§ 192.619
(paragraph)
(a)
(a)(1)
(a)(2)
(a)(3)
(a)(4)
(c)
(d)
Other
Methodology Description
Introduction: Except as specified in (c) and (d), use the lowest MAOP
determined by (a)(1), (a)(2), (a)(3), (a)(4).
Design Pressure
Post-Construction Pressure Test
High Actual Operation Pressure during 5 years preceding July 1, 1970 – this is
NOT the Grandfather Clause
History of Pipe (primarily corrosion and actual operating pressure)
Grandfather Clause – Highest Actual Operating Pressure during 5 years
preceding 1970, even if this MAOP is higher than pressures determined by other
methodologies in (a)
Alternative MAOP (§ 192.620) and Alternative MAOP Special Permits
Use this category if you did not base your MAOP on any of the paragraphs
within § 192.619 or 192.624(c)
E2b. and E2c. Enter the date the MAOP was established and indicate if the MAOP was established
in conjunction with a flow reversal.
E3. Pressure Description
Select the option that describes the relationship among the operating pressure at the point and time
of the incident, the MAOP, and the allowances in §192.201.
E4. Was the system or facility relating to the Incident operating under an established pressure
restriction with pressure limits below those normally allowed by the MAOP ?
Consider both voluntary and mandated pressure restrictions. A pressure restriction is to be
considered mandated by PHMSA or a state regulator if it was required by an Order, enforcement
action, or other formal correspondence from PHMSA.
Page 24 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
An “established pressure restriction” is defined as a temporary reduction in the MAOP that also
requires a revision to the set points in the operator’s safety devices, processes or controls to ensure
the pressure restriction is not exceeded.
Pressure reductions taken by the operator as a result of a procedural or regulatory requirement, e.g.,
pipeline repairs, movement, investigations, or a pressure reduction taken because an anomaly
identified during an IM assessment could not be repaired within the required schedule
(§192.933(d)), are not considered “mandated by PHMSA.”
E5. Odorization Indicate if the gas at the point of failure was required to be odorized. If it was
required, indicate if the odorization was in accordance with §192.615.
If A14. is “Onshore Pipeline, Including Valve Sites” OR “Offshore Pipeline, Including Riser and
Riser Bend”, answer E6 through E8.
E6. Length of segment isolated between valves (ft)
Identify the length in feet between the upstream and downstream shut-off valves closest to the
failure location.
E9. Function of pipeline system
Transmission System means pipelines that are part of a system whose principal purpose is
transmission of gas.
Transmission Line of Distribution System means a pipeline that meets the definition of
“transmission line” in §192.3 but which is operated as part of a distribution pipeline system.
Typically, this includes portions of the distribution pipeline system for which the operating stress
level exceeds 20 percent SMYS.
Type A, Type B, and Type C Gathering means a pipeline that transports gas from a current
production facility to a transmission line or main and that meets the criteria for either Type A, Type
B, or Type C in §192.8. For Type R gas gathering, report incidents on Form PHMSA F 7100.2-2.
Offshore Gathering means a gas gathering pipeline located offshore.
Transmission in Storage Field means a transmission pipeline that transports gas within a storage
field.
E10. Was a Supervisory Control and Data Acquisition (SCADA)-based system in place on the
pipeline or facility involved in the Incident?
This does not mean a system designed or used exclusively for leak detection.
E10a. Was it operating at the time of the Incident?
Was the SCADA system in operation at the time of the incident?
Page 25 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
E10b. Was it fully functional at the time of the Incident?
Was the SCADA system capable of performing all of its functions, whether or not it
was actually in operation at the time of the incident? If No, describe functions that
were not operational in PART H – Narrative Description of the Incident.
E10c and d. Did SCADA-based information (such as alarm(s), alert(s), event(s),
and/or volume or pack calculations) assist with the initial indication or confirmed
discovery of the Incident?
Select Yes if SCADA-based information was used to confirm the incident even if the
initial report or identification may have come from other sources. Use of SCADA data
for subsequent estimation of amount of gas lost, etc. is not considered use to confirm
the incident.
Select No if SCADA-based information was not used to assist with identification of the
incident.
E11. Was an investigation initiated into whether or not the controller(s) or control room issues
were the cause of or a contributing factor to the Incident?
Select only one of the choices to indicate whether an investigation was/is being conducted (Yes) or
was not conducted (No). If an investigation has been completed, select all the factors that apply in
describing the results of the investigation.
Cause means an action or lack of action that directly led to or resulted in the pipeline incident.
Contributing factor means an action or lack of action that when added to the existing pipeline
circumstances heightened the likelihood of the release or added to the impact of the release.
Controller Error means that the controller failed to identify a circumstance indicative of a release
event, such as an abnormal operating condition, alarm, pressure drop, change in flow rate, or other
similar event.
Incorrect Controller action means that the controller errantly operated the means for controlling
an event. Examples include opening or closing the wrong valve, or hitting the wrong switch or
button.
PART F – DRUG & ALCOHOL TESTING INFORMATION
Requirements for post-incident drug and alcohol tests are in 49 CFR §199.105 and §199.225
respectively. If the incident circumstances were such that tests were not required by these
regulations, and if no tests were conducted, select No. If tests were administered, select Yes and
report separately the number of operator employees and the number of contractors working for the
operator who were tested and the number of each that failed such tests.
Page 26 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
PART G – APPARENT CAUSE
PART G – Apparent Cause
Select the one, single sub-cause listed under sections G1 thru G8 that best describes the apparent
cause of the Incident. These sub-causes are contained in the shaded column on the left under each
main cause category. Answer the corresponding questions that accompany your selected subcause, and enter any secondary, contributing, or root causes of the Incident in PART K –
Contributing Factors. Make every effort to find a category that fits the Incident’s Apparent
Cause and avoid the use of Other and Unknown when possible. Use of Unknown as an
Apparent Cause will require the submittal of a Supplemental Report to revise the Apparent
Cause when it becomes known.
G1 – Corrosion Failure
Corrosion includes a release or failure caused by galvanic, atmospheric, stray current,
microbiological, selective seam, or other corrosive action. A corrosion release or failure is not
limited to a hole in the pipe or other piece of equipment. If the bonnet or packing gland on a valve
or flange on piping deteriorates or becomes loose and leaks due to corrosion and failure of bolts, it
is to be classified as Corrosion. (Note: If the bonnet, packing, or other gasket has deteriorated to
failure, whether before or after the end of its expected life, but not due to corrosive action, it is to
be classified under G6 - Equipment Failure.)
External Corrosion
2. Type of corrosion – NOTE: Stress Corrosion Cracking (SCC) is no longer an option for the
type of corrosion. SCC failures are to be reported under cause G5, with a sub-cause of
Environmental Cracking-related.
If Stray Current corrosion is selected, specify whether alternating or direct current was involved
and describe the source of the stray current.
4a. Under cathodic protection means cathodic protection in accordance with §192.455,
§192.457, and §192.463. Recognizing that older pipelines may have had cathodic protection added
over a number of years, provide an estimate if the exact year cathodic protection started is unknown.
Internal Corrosion
9. Location of corrosion
A low point in pipe includes portions of the pipe contour in which water might settle out. This
includes, but is not limited to, the low point of vertical bends at a crossing of a foreign line or
road/railroad, etc., an elbow, a drop out or low point drain.
10. Was the gas/fluid treated with corrosion inhibitors or biocides?
Page 27 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
Select Yes if corrosion inhibitors or biocides were included in the gas/fluid transported.
12. Were cleaning/dewatering pigs (or other operations) routinely utilized?
13. Were corrosion coupons routinely utilized?
For purposes of these Questions 12 and 13, “routinely” refers to an action that is performed on more
than a sporadic or one-time basis as part of a regular program with the intent to ensure that water
build-up and/or settling and internal corrosion do not occur.
G2 – Natural Force Damage
Natural Force Damage includes a release or failure resulting from earth movement, earthquakes,
landslides, subsidence, lightning, heavy rains/floods, washouts, flotation, mudslide, scouring,
temperature, frost heave, frozen components, high winds, or similar natural causes.
Earth Movement NOT due to Heavy Rains/Floods refers to incidents caused by land shifts such
as earthquakes, landslides, or subsidence, but not mudslides which are presumed to be initiated by
heavy rains or floods.
Heavy Rains/Floods refer to all water-related natural force causes. While mudslides involve earth
movement, report them here since typically they are an effect of heavy rains or floods.
Lightning includes both damage and/or fire caused by a direct lighting strike and damage and/or
fire as a secondary effect from a lightning strike in the area. An example of such a secondary effect
would be a forest fire started by lightning that results in damage to a pipeline system asset which
results in an incident.
Temperature includes weather-related temperature and thermal stress effects, either heat or cold,
where temperature was the initiating cause.
Thermal stress refers to mechanical stress induced in a pipe or component when
some or all of its parts are not free to expand or contract in response to changes
in temperature.
Frozen components would include incidents where components are inoperable
because of freezing and those due to cracking of a piece of equipment due to
expansion of water during a freeze cycle.
High Winds includes damage caused by wind-induced forces. Select this category if the damage
is due to the force of the wind itself. Damage caused by impact from objects blown by wind would
be reported under G4 - Other Outside Force Damage.
Tree/Vegetation Root includes damages caused by tree and vegetation roots.
Page 28 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
Snow/Ice impact or Accumulation should be indicated when snow and/or ice caused damage to
the gas transmission and gathering system asset which results in an incident.
Other Natural Force Damage. Select this sub-cause for types of Natural Force Damage not
included otherwise, and describe in the space provided. If necessary, provide additional explanation
in PART H – Narrative Description of the Incident.
Answer Questions 6 and 6.a if the incident occurred in conjunction with an extreme weather event
such as a hurricane, tropical storm, or tornado. If an extreme weather event related to something
other than a hurricane, tropical storm, or tornado was involved, indicate Other and describe the
event in the space provided.
G3 – Excavation Damage
Excavation Damage includes a release or failure resulting directly from excavation damage by
operator's personnel (oftentimes referred to as “first party” excavation damage) or by the operator’s
contractor (oftentimes referred to as “second party” excavation damage) or by people or contractors
not associated with the operator (oftentimes referred to as “third party” excavation damage). Also,
this section includes a release or failure determined to have resulted from previous damage due to
excavation activity. For damage from outside forces OTHER than excavation which results in a
release, use G2 - Natural Force Damage or G4 - Other Outside Force, as appropriate. Also, for a
strike, physical contact, or other damage to a pipeline or facility that apparently was NOT related
to excavation and that results in a delayed or eventual release, report the incident under G4 as
“Previous Mechanical Damage NOT related to Excavation.”
Excavation Damage by Operator (First Party) refers to incidents caused as a result of excavation
by a direct employee of the operator.
Excavation Damage by Operator’s Contractor (Second Party) refers to incidents caused as a
result of excavation by the operator’s contractor or agent or other party working for the operator.
Excavation Damage by Third Party refers to incidents caused by excavation damage resulting
from actions by personnel or other third parties not working for or acting on behalf of the operator
or its agent.
Previous Damage due to Excavation Activity refers to incidents that were apparently caused by
prior excavation activity and that then resulted in a delayed or eventual release. Indications of prior
excavation activity might come from the condition of the pipe when it is examined, or from records
of excavation at the site, or through metallurgical analysis or other inspection and/or testing
methods. Dents and gouges in the 10:00-to-2:00 o’clock positions on the pipe, for instance, may
indicate an earlier strike, as might marks from the bucket or tracks of an earth moving machine or
similar pieces of equipment.
Page 29 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
If any Excavation Damage suc-cause is selected, answer questions 1 through 14.
1. and 1a. Prior Notification Indicate whether you received prior notification of the excavation
activity. If yes, indicate all of the notification sources.
1b. through 1d. One-Call State Law Exemptions Per the primary Incident Investigator results,
indicate whether State law exempted the excavator from notifying a one-call center. If yes, select
the type of exemption from the list. If “Other” is selected, enter text describing the exemption.
Describe the exempting authority and exempting criteria.
3. – 14. Complete these questions for any excavation damage sub-cause. Instructions for
answering these questions can be found at https://www.phmsa.dot.gov/operatorresources/damage-information-reporting-tool-dirt-users-guide
NOTE: If you have or will be reporting the information in questions 3 thru 14 to CGA-DIRT,
select “No” in question 2 to avoid duplication of data submitted to CGA.
G4 – Other Outside Force Damage
Other Outside Force Damage includes, but is not limited to, a release or failure resulting from
non-excavation-related outside forces, such as nearby industrial, man-made, or other fire or
explosion; damage by vehicles or other equipment; failures due to mechanical damage; and,
intentional damage including vandalism and terrorism.
Nearby Industrial, Man-made or other Fire/Explosion as Primary Cause of Incident applies
to situations where the fire occurred before - and caused - the release. (See also the discussion of
“secondary ignition” under the General Instructions.) Examples of such an incident would be an
explosion or fire that originated at a neighboring facility or installation (chemical plant, tank farm,
or other industrial facility) or structure, debris, or brush/trees that results in a release at the
operator’s pipeline or facility. This includes forest, brush, or ground fires that are caused by human
activity. If the fire, however, is known to have been started as a result of a lightning strike, the
incident’s cause is to be classified under G2 - Natural Force Damage. Arson events directed at
harming the pipeline or the operator are to be reported as G4 - Intentional Damage (see below).
Damage by Car, Truck, or Other Motorized Vehicle/Equipment NOT Engaged in Excavation.
An example of this sub-cause would be a stopple tee that releases gas when damaged by a pickup
truck maneuvering near the pipeline. Other motorized vehicles or equipment include tractors,
backhoes, bulldozers and other tracked vehicles, and heavy equipment that can move. Include
under this sub-cause incidents caused by vehicles operated by the pipeline operator, the pipeline
operator’s contractor, or a third party and specify the vehicle/equipment operator’s affiliation from
one of these three groups. Pipeline incidents resulting from vehicular traffic loading or other
contact are to also be reported in this category. If the activity that caused the incident involved
digging, drilling, boring, blasting, grading, cultivation or similar excavation activities, report under
G3 - Excavation Damage.
Page 30 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
Damage by Boats, Barges, Drilling Rigs, or Other Maritime Equipment or Vessels Set Adrift
or Which Have Otherwise Lost Their Mooring. This sub-cause includes impacts by maritime
equipment or vessels (including their anchors or anchor chains or other attached equipment) that
have lost their moorings and are carried into the pipeline facility by the current. This sub-cause
also includes maritime equipment or vessels set adrift as a result of severe weather events and
carried into the pipeline facility by waves, currents, or high winds. In such cases, also indicate the
type of severe weather event. Do NOT report in this sub-cause incidents which are caused by the
impact of maritime equipment or vessels while they are engaged in their normal or routine activities;
such incidents are to be reported as “Routine or Normal Fishing or Other Maritime Activity NOT
Engaged in Excavation” under this section G4 (see below) so long as those activities are not
excavation activities. If those activities are excavation activities such as dredging or bank
stabilization or renewal, the incident is to be reported under G3 - Excavation Damage.
Routine or Normal Fishing or Other Maritime Activity NOT Engaged in Excavation. This
sub-cause includes incidents due to shrimping, purse seining, dredging, oil drilling, or oilfield
workover rigs, including anchor strikes, and other routine or normal maritime-related activities
UNLESS: the movement of the maritime asset was inadvertent and due to a severe weather event
(this type of incident is to be reported under “Damage by Boats, Barges, Drilling Rigs, or Other
Maritime Equipment or Vessels Set Adrift or Which Have Otherwise Lost Their Mooring” in this
section G4); or, the incident was caused by excavation activity such as dredging of waterways or
bodies of water (this type of incident is to be reported under G3 - Excavation Damage).
Electrical Arcing from Other Equipment or Facility such as a pole transformer or adjacent
facility’s electrical equipment.
Previous Mechanical Damage NOT Related to Excavation. This sub-cause covers incidents
where damage occurred at some time prior to the release that was apparently NOT related to
excavation activities, and would include prior outside force damage of an unknown nature, prior
natural force damage, prior damage from other outside forces, and any other previous mechanical
damage other than that which was apparently related to prior excavation. Incidents resulting from
previous damage sustained during construction, installation, or fabrication of the pipe or weld from
which the release eventually occurred are to be reported under G5 - Material Failure of Pipe or
Weld. (See this sub-cause for typical indications of previous construction, installation, or
fabrication damage.) Incidents resulting from previous damage sustained as a result of excavation
activities should be reported under G3 – Previous Damage due to Excavation Activity. (See this
sub-cause for typical indications of prior excavation activity.)
Intentional Damage
Vandalism means willful or malicious destruction of the operator’s pipeline facility or
equipment. This category would include arson, pranks, systematic damage inflicted to
harass the operator, motor vehicle damage that was inflicted intentionally, and a variety
of other intentional acts. (See also the discussion of “secondary ignition” under the
General Instructions.)
Page 31 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
Terrorism, per 28 CFR §0.85 General Functions, includes the unlawful use of force
and violence against persons or property to intimidate or coerce a government, the
civilian population, or any segment thereof, in furtherance of political or social
objectives. Operators selecting this item are encouraged to also notify the FBI.
Theft of commodity or Theft of equipment means damage by any individual or entity,
by any mechanism, specifically to steal, or attempt to steal, the transported gas or
pipeline equipment.
Other Describe in the space provided and, if necessary, provide additional explanation
in PART H – Narrative Description of the Incident.
Other Outside Force Damage. Select this sub-cause for types of Other Outside Force Damage
not included otherwise, and describe in the space provided. If necessary, provide additional
explanation in PART H – Narrative Description of the Incident.
5 – 11 Additional Data for Damage by Car, Truck, or Other Motorized Vehicle/Equipment
NOT Engaged in Excavation
When answering the questions, include information that can be substantiated from police reports or
other investigative reports.
The following definitions apply for reporting the type of motorized vehicle in Question 10:
Motorcycle/All-Terrain Vehicle (ATV) - All two or three-wheeled motorized vehicles, and some
four-wheeled vehicles are to be reported in this category. Typical vehicles in this category have
saddle type seats and are steered by handlebars rather than steering wheels. This category includes
motorcycles, motor scooters, mopeds, motor-powered bicycles, and three-wheel motorcycles.
Additionally, four-wheeled off-road and all-terrain vehicles (sometimes referred to as “fourwheelers”) are to be reported under this category.
Passenger Car -- All sedans, coupes, and station wagons manufactured primarily for the purpose
of carrying passengers and including those passenger cars pulling recreational or other light
trailers.
Small Truck - All two-axle, four-tire, vehicles, other than passenger cars. Included in this
classification are pickups, panels, vans, and other vehicles such as campers, motor homes,
ambulances, hearses, carryalls, and minibuses.
Bus - All vehicles manufactured as traditional passenger-carrying buses with two axles and six
tires or three or more axles. This category includes only traditional buses (including school buses)
functioning as passenger-carrying vehicles. Modified buses should be considered to be a truck
and should be appropriately classified.
Large Truck - All vehicles on a single frame including trucks, camping and recreational vehicles,
motor homes, etc., with two or more axles and at least two rear wheels on each side
Page 32 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
When specifying the type of protection in Question 13; select the category “Barricades” for Jersey
barriers, fencing, and other structures that are other than Guard Rails or Bollards/Guard Posts. If
“Other” is selected, enter text describing the protection.
G5 – Material Failure of Pipe or Weld
Use this section to report material failures only if “Item Involved in Incident” (PART C, Question
3) is “Pipe” (whether “Pipe Body” or “Pipe Seam”) or “Weld.” Indicate how the sub-cause was
determined or if the sub-cause is still being investigated.
This section includes releases in or failures from defects or anomalies within the material of the
pipe body or within the pipe seam or other weld due to manufacturing processes, material
imperfections, defects resulting from poor construction, installation, or fabrication practices, and
in-service stresses such as vibration, fatigue, and environmental cracking.
Design-, Construction-, Installation-, or Fabrication-related includes a release or failure caused
by improper design practices, a dent, gouge, excessive stress, or some other defect or anomaly
introduced during the process of constructing, installing, or fabricating pipe and pipe welds in the
field, including welding or other activities performed at the construction job site. Included are
releases from or failures of wrinkle bends, field welds, and damage sustained in transportation to
the construction or fabrication site. Not included are failures due to seam defects, which are to be
reported as Original Manufacturing-related (see below). If a river crossing were directionally
drilled and tied into a buried pipeline without adequate accommodation for expansion and
contraction of the pipe in the drill hole and the pipeline facility fails at the tie-in, this represents an
improper design practice. Select “Design-, Construction-, Installation-, or Fabrication-related” as
the sub-cause.
Original Manufacturing-related (NOT girth welds or other welds formed in the field) includes
a release or failure caused by a defect or anomaly introduced during the process of manufacturing
pipe, including manufacturing and handling of the plate materials, seam defects and defects in the
pipe body. This option is not appropriate for wrinkle bends, field welds, girth welds, or other joints
fabricated in the field. Use this option for failures such as those due to defects of the longitudinal
weld or inclusions in the pipe body. If the girth welds were completed at the pipe mill (such as in
the case of double joints welded prior to delivery to the jobsite) report those failures in this category.
Environmental Cracking-related includes failures by Stress Corrosion Cracking, Sulfide Stress
Cracking, Hydrogen Stress Cracking, Hard Spots or other environmental cracking mechanisms.
If Design-, Construction-, Installation-, or Fabrication-related, or Original Manufacturingrelated is selected, then select any contributing factors. Examples of Mechanical Stress include
failures related to overburden or loss of support.
5. Post-construction Pressure Test
If you know the post-construction pressure test value, enter it in psig.
“Unknown.”
Page 33 of 38
Otherwise, select
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
G6 – Equipment Failure
This section applies to failures of items other than “Pipe” (“Pipe Body” or “Pipe Seam”) or
“Weld”.
Equipment Failure includes a release or failure resulting from: malfunction of control/relief
equipment including valves, regulators, or other instrumentation; failures of compressors, or
compressor-related equipment; failures of various types of connectors, connections, and
appurtenances; failures of the body of equipment, vessel plate, or other material (including those
caused by construction-, installation-, or fabrication-related and original manufacturing-related
defects or anomalies); and, all other equipment-related failures.
Malfunction of Control/Relief Equipment. Examples of this type of incident cause include:
overpressurization resulting from malfunction of a control or alarm device; malfunction of a relief
valve; valves failing to open or close on command; or valves which opened or closed when not
commanded to do so. If overpressurization or some other aspect of this incident was caused by
incorrect operation involving human error, the incident is to be reported under G7 - Incorrect
Operation.
ESD System Failure means failure of an emergency shutdown system.
Other Equipment Failure. Select this sub-cause for types of Equipment Failure not included
otherwise, and describe in the space provided. If necessary, provide additional explanation in
PART H – Narrative Description of the Incident.
G7 – Incorrect Operation
Incorrect Operation includes a release or failure resulting from operating, maintenance, repair, or
other errors by facility personnel or pipeline controllers, including, but not limited to improper valve
selection or operation, inadvertent overpressurization, or improper selection or installation of
equipment in the field. If the failure occurs in the pipe body or weld, and is a result of inadequate
design or a design error, the Incident is to be reported under G5 – Material Failure of Pipe or Weld,
Design-, Construction-, Installation-, or Fabrication-related.
Other Incorrect Operation. Select this sub-cause for types of Incorrect Operation not included
otherwise, and describe in the space provided. If necessary, provide additional explanation in
PART H – Narrative Description of the Incident.
G8 – Other Incident Cause
This section is provided for incidents whose cause is currently unknown, or where investigation
into the cause has been exhausted and the final judgment as to the cause remains unknown, or where
a cause has been determined which does not fit into any of the main cause categories listed in
sections G1 thru G7. PHMSA will review all G-8 cause selections and determine if it meets the
definition of any category listed in G1 thru G7 before a Final Report is accepted for closure. All
Page 34 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
sub cause categories of “Unknown” require a Supplemental Report to be filed before being
accepted as Final.
If the incident cause is known but doesn’t fit into any category in sections G1 thru G7, select
Miscellaneous and enter a description of the incident cause, continuing with a more thorough
explanation in PART H - Narrative Description of the Incident.
If the incident cause is unknown at the time of filing this report, select Unknown in this section
and specify one reason from the accompanying two choices. Once the operator’s investigation into
the incident cause is completed, the operator is to file a Supplemental Report as soon as practicable
either reporting the apparent cause or stating definitively that the cause remains Unknown, along
with any other new, updated, and/or corrected information pertaining to the incident. This
Supplemental Report is to include all new, updated, and/or corrected information pertaining to all
portions of the report form known at this time, and not only that information related to the apparent
cause.
Important Note: Whether the investigation is completed or not, or if the cause continues to be
unknown, Supplemental Reports are to be filed reflecting new, updated, and/or corrected
information as and when this information becomes available. In those cases in which
investigations are ongoing for an extended period of time, operators are to file a Supplemental
Report within one year of their last report for the incident even in those instances where no new,
updated, and/or corrected information has been obtained, with an explanation that the cause remains
under investigation in PART H – Narrative Description of Incident. Additionally, final
determination of the apparent cause and/or closure of the investigation does NOT preclude the need
for the operator’s filing of additional Supplemental Reports as and when new, updated, and/or
corrected information becomes available.
Page 35 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
PART J – INTEGRITY INSPECTIONS
Complete the following if the “Item Involved in Accident” (from PART C, Question 3) is Pipe
or Weld and the “Cause” (from Part G) is:
Corrosion (any subCause in Part G1); or
Previous Damage due to Excavation Activity (subCause in Part G3); or
Previous Mechanical Damage NOT Related to Excavation (subCause in Part G4); or
Material Failure of Pipe or Weld (any subCause in Part G5)
J1. Internal Inspection Tools
If Yes, for each tool and technology used, select type of internal inspection tool and technology,
and indicate year of most recent and previous runs.
Axial Magnetic Flux Leakage (MFL) is an in-line inspection (ILI) tool that uses a non-destructive
testing (NDT) method of imposing a magnetic flux in the steel pipe for the detection of corrosion
and pitting. The basic principle behind MFL ILI involves magnetizing the steel pipe to a saturation
level with a magnetic field. MFL ILI tools can be either low- and high-resolution tools, with more
modern tools being high-resolution MFL ILI tools.
Circumferential/Transverse Wave Magnetic Flux Leakage (MFL) is an in-line inspection (ILI)
tool that induces the magnetic flux field into the steel pipe in the circumferential direction, which
allows the measurement of longitudinally oriented anomalies such as tunnel corrosion and
longitudinal weld anomalies.
Ultrasonic is an in-line inspection (ILI) tool that introduces a shear wave ultrasound beam into the
steel pipeline inspection area at an angle, which allows detection of abnormalities based on the
reflection and refraction of the beam. Can be used to detect and size planar (crack and crack-like)
anomalies or measure wall thickness and detect instances of wall loss.
Geometry/Deformation is an in-line inspection (ILI) tool designed to record mechanical or
geometric conditions such as changes in the pipe internal diameter, including dents, ovalities,
wrinkles, expansions, and misalignments.
Electromagnetic Acoustic Transducer (EMAT) is an in-line inspection (ILI) tool that generates
an ultrasonic pulse within the steel pipe without a liquid couplant. EMAT ILI consists of a magnet
and an electrical coil, which uses electro-magnetic forces to introduce sound energy into the steel
pipe. EMAT ILI is used to detect cracking flaws in steel pipe.
Cathodic Protection Current Measurement (CPCM) is an in-line inspection (ILI) tool capable
of reading and recording the magnitude and polarity of current supplied by cathodic protection
(CP). CPCM ILI measures direct current (DC) and alternating current (AC) voltage gradients from
CP current or induced AC as the CPCM ILI tool traverses along the pipeline.
Page 36 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
Complete J1b. only when the “Cause” (from Part G) is:
Previous Damage due to Excavation Activity (subCause in Part G3); or
Previous Mechanical Damage NOT Related to Excavation (subCause in Part G4)
J1b. Indicate if you have reason to believe the internal inspections were completed before the
damage was sustained.
J2. Hydrotest Has one or more hydrotest or other pressure test been conducted since original
construction at the point of the Incident?
Information from the initial post-construction hydrostatic test is NOT reported in J2.
J3. Direct Assessment (DA) Has Direct Assessment been conducted on this segment?
This refers to direct assessment as defined in §192.903. Instances in which one or more indirect
monitoring tools (e.g., close interval survey, DCVG) have been used that might be used as part of
direct assessment but which have not been used as part of the direct assessment process defined in
§192.903 do NOT constitute a Direct Assessment for purposes of this question.
If J3. is yes, enter the year of the most recent assessment(s) in J3a.
J4. Non-destructive Examination
Indicate if one or more non-destructive examination been conducted prior to the Incident at the
point of the Incident since January 1, 2002. If Yes, enter the most recent year of the examination(s)
in J4a.
PART K – CONTRIBUTING FACTORS
Contributing factor means an action or lack of action that when added to the existing
circumstances heightened the likelihood of the release or added to the impact of the release. The
Apparent Cause of the accident is contained in Part G. Do not report the Apparent Cause again in
this Part K. If Contributing Factors were identified, select all that apply and explain each in the
Narrative.
PART H – NARRATIVE DESCRIPTION OF THE INCIDENT
Concisely describe the incident, including the facts, circumstances, and conditions that may have
contributed directly or indirectly to causing the incident. Include secondary, contributing, or root
causes when possible, or any other factors associated with the cause that are deemed pertinent. Use
this section to clarify or explain unusual conditions, and to explain any estimated data.
If you selected Miscellaneous in section G8, the narrative is to describe the incident in detail,
including all known or suspected causes and possible contributing factors.
Page 37 of 38
Instructions (rev 3-2022) for Form PHMSA F 7100.2 (rev 3-2022)
INCIDENT REPORT – GAS TRANSMISSION, GAS GATHERING, AND UNDERGROUND NATURAL GAS
STORAGE FACILITIES
PART I – PREPARER AND AUTHORIZED PERSON
The Preparer is the person who compiled the data and prepared the responses to the report and who
is to be contacted for more information (preferably the person most knowledgeable about the
information in the report or who knows how to contact the person or persons most knowledgeable).
Enter the Preparer’s e-mail address if the Preparer has one, and the phone and fax numbers used by
the Preparer.
The Authorized Person is responsible for assuring the accuracy and completeness of the reported
data. In addition to their title, a phone number and email address are to be provided for the
Authorized Person.
Page 38 of 38
| File Type | application/pdf |
| Author | PHMSA |
| File Modified | 2023-08-03 |
| File Created | 2023-08-03 |