Phmsa F 7100.2 Incident Report Gas Transmission And Gathering Pipeline

Incident and Annual Reports for Gas Pipeline Operators

GT GG INCIDENTForm wInstruct09212012

Incident and Annual Reports for Gas Pipeline Operators

OMB: 2137-0522

⚠️ Notice: This form may be outdated. More recent filings and information on OMB 2137-0522 can be found here:

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NOTICE: This report is required by 49 CFR Part 191. Failure to report can result in a civil penalty not to exceed
$100,000 for each violation for each day that such violation persists except that the maximum civil penalty shall not
exceed $1,000,000 as provided in 49 USC 60122.

Form Approved
OMB NO: 2137-0522
Expires: 01/31/2014

INCIDENT REPORT –
NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

U.S. Department of Transportation
Pipeline and Hazardous Materials
Safety Administration

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 2137-0522. Public reporting for this
collection of information is estimated to be approximately 10 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

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.
PART A – KEY REPORT INFORMATION

 Original

*Report Type: (select all that apply)

*1. Operator’s OPS-issued Operator Identification Number (OPID):

 Supplemental

 Final

*2. Name of Operator: ______________________________________________________________________________________
*3. Address of Operator:
*3.a _______________________________________________________________________
(Street Address)

*3.b ___________________________________________________
(City)

*3.c State: /

*3.d Zip Code: /

/ - /

*4. Local time (24-hr clock) and date of the Incident:
/

Hour

Month

*5. Location of Incident:
*Latitude:
/ / / . / /
*Longitude: - / / / / . /

6. National Response Center Report Number:

Day

Year

7. Local time (24-hr clock) and date of initial telephonic report to the
National Response Center (if applicable):
/
/

/
/

Hour

Month

/
Day

Year

*8. Incident resulted from:
 Unintentional release of gas
 Intentional release of gas
 Reasons other than release of gas
*9. Gas released: (select only one, based on predominant volume released)







Natural Gas
Propane Gas
Synthetic Gas
Hydrogen Gas
Other Gas



Name:

*10. Estimated volume of gas released unintentionally:
11. Estimated volume of intentional and controlled release/blowdown :
12. Estimated volume of accompanying liquid released:

/
/

/,/
/,/

/,/

Form PHMSA F 7100.2 (Rev. xy-2012 )

/
/

/ Thousand Cubic Feet (MCF)
/ Thousand Cubic Feet (MCF)

/ Barrels

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*13. Were there fatalities?  Yes  No
If Yes, specify the number in each category:

*14. Were there injuries requiring inpatient hospitalization?
If Yes, specify the number in each category:

 Yes  No

*13.a Operator employees

*14.a Operator employees

*13.b Contractor employees
working for the Operator

*14.b Contractor employees
working for the Operator

*13.c Non-Operator
emergency responders

*14.c Non-Operator
emergency responders

*13.d Workers working on the
right-of-way, but NOT
associated with this Operator

*14.d Workers working on the
right-of-way, but NOT
associated with this Operator

*13.e General public

*14.e General public

13.f Total fatalities (sum of above)

14.f Total injuries (sum of above)

15. Was the pipeline/facility shut down due to the incident?
 Yes  No  Explain: ______________________________________________________________________________
If Yes, complete Questions 15.a and 15.b: (use local time, 24-hr clock)
15.a Local time and date of shutdown

Hour

15.b Local time pipeline/facility restarted

Hour

*16. Did the gas ignite?

 Yes

 No

*17. Did the gas explode?

 Yes

 No

18. Number of general public evacuated: /

/,/

Month

Day

Year

Day

 Still shut down*
(*Supplemental Report required)

Year

19. Time sequence: (use local time, 24-hour clock)
19.a Local time operator identified Incident

Hour

19.b Local time operator resources arrived on site

/
Hour

Month

/
Month

Form PHMSA F 7100.2 (Rev. xy-2012 )

Day

/
Day

Year

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PART B – ADDITIONAL LOCATION INFORMATION
*1. Was the origin of the Incident onshore?
 Yes (Complete Questions 2-12)

 No (Complete Questions 13-15)

If Onshore:
*2. State: /

If Offshore:
/

*3. Zip Code: /

*13. Approximate water depth (ft.) at the point of the Incident:
/

4 ______________________

/ - /

5______________________

City

County or Parish

6. Operator designated location: (select only one)
 Milepost/Valve Station (specify in shaded area below)

/,/

*14. Origin of Incident:

 In State waters
 Specify: State: /

/
/
Area: ___________________

Block/Tract #: /___/___/___/___/

 Survey Station No. (specify in shaded area below)

Nearest County/Parish: ________________
/___/___/___/___/___/___/___/___/___/___/___/___/___/
7. Pipeline/Facility name: ________________________________

 On the Outer Continental Shelf (OCS)
 Specify: Area: ___________________
Block #: /___/___/___/___/

8. Segment name/ID: ___________________________________
*9. Was Incident on Federal land, other than the Outer Continental
Shelf (OCS)?
 Yes  No
*10. Location of Incident: (select only one)

 Operator-controlled property
 Pipeline right-of-way

*15. Area of Incident: (select only one)








Shoreline/Bank 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

*11. 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
 In underground enclosed space (e.g., vault)
 Other ____________________________
Depth-of-Cover (in): /

/,/

 Aboveground  Specify:
 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 ____________________________
*12. Did Incident occur in a crossing?
If Yes, specify type below:
 Bridge crossing  Specify:

 Yes

 No

 Cased  Uncased
 Railroad crossing  (select all that apply)
 Cased
 Uncased
 Bored/drilled
 Road crossing 
(select all that apply)
 Cased
 Uncased
 Bored/drilled
 Water crossing
 Uncased
 Specify:  Cased
Name of body of water, if commonly known:
_____________________________________
Approx. water depth (ft) at the point of the Incident:
/

/,/

(select only one of the following)

 Shoreline/Bank 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

Form PHMSA F 7100.2 (Rev. xy-2012 )

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PART C – ADDITIONAL FACILITY INFORMATION
*1. Is the pipeline or facility:
 Interstate
 Intrastate
*2. 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
*3. Item involved in Incident: (select only one)

 Pipe  Specify:

 Pipe Body

 Pipe Seam

3.a Nominal diameter of pipe (in):

3.b Wall thickness (in):

/./

3.c SMYS (Specified Minimum Yield Strength) of pipe (psi):

/,/

3.d Pipe specification: _____________________________
*3.e Pipe Seam

 Specify:  Longitudinal ERW - High Frequency
 Longitudinal ERW - Low Frequency
 Longitudinal ERW – Unknown Frequency
 Spiral Welded ERW
 Spiral Welded SAW
 Lap Welded
 Seamless

 Single SAW
 DSAW

 Flash Welded
 Continuous Welded
 Furnace Butt Welded

 Spiral Welded DSAW
 Other ________________________

3.f Pipe manufacturer: _______________________________
3.g Year of manufacture: /
/
/
/
/
*3.h Pipeline coating type at point of Incident
 Fusion Bonded Epoxy
 Specify:

 Coal Tar
 Asphalt
 Polyolefin
 Extruded Polyethylene  Field Applied Epoxy  Cold Applied Tape  Paint
 Composite
 None
 Other _______________________________
 Weld, including heat-affected zone  Specify:  Pipe Girth Weld  Other Butt Weld  Fillet Weld  Other_____________
If Pipe Girth Weld is selected, complete items 3.a. through h. above. If the values differ on either side of the girth weld, enter one value in
3.a. through h. and list the different value(s) in Part H - Narrative Description of the Incident.
 Valve
 Mainline  Specify:  Butterfly  Check  Gate  Plug  Ball  Globe

 Other __________________________
3.i Mainline valve manufacturer:
3.j Year of manufacture: /
/
/
/
/























 Relief Valve
 Auxiliary or Other Valve
Compressor
Meter
Scraper/Pig Trap
Separator/Separator Filter
Strainer/Filter
Dehydrator/Drier/Treater
Regulator/Control Valve
Drip/Drip Collection Device
Pulsation Bottle
Cooler
Repair Sleeve or Clamp
Hot Tap Equipment
Stopple Fitting
Flange
Relief Line
Auxiliary Piping (e.g. drain lines)
Tubing
Instrumentation
Underground Gas Storage or Cavern
Pressure Vessel
Other ___________________________________

4. Year item involved in Incident was installed:

Form PHMSA F 7100.2 (Rev. xy-2012 )

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*5. Material involved in Incident: (select only one)

 Carbon Steel
 Plastic
 Material other than Carbon Steel or Plastic



*Specify: ____________________________________________

*6. Type of Incident involved: (select only one)

 Mechanical Puncture  Approx. size: /__/__/__/__/./__/in. (axial) by /__/__/__/__/./__/in. (circumferential)
 Leak  Select Type:  Pinhole
 Crack
 Connection Failure
 Seal or Packing
 Other
 Rupture  Select Orientation:  Circumferential
 Longitudinal
 Other ________________________________
Approx. size: /__/__/__/__/./__/ in. (widest opening) by /__/__/__/__/__/./__/in. (length circumferentially or axially)

 Other



*Describe: ___________________________________________________________________

Form PHMSA F 7100.2 (Rev. xy-2012 )

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PART D – ADDITIONAL CONSEQUENCE INFORMATION
*1. Class Location of Incident: (select only one)
 Class 1 Location

 Class 2 Location
 Class 3 Location
 Class 4 Location
*2. Did this Incident occur in a High Consequence Area (HCA)?
 No
 Yes  2.a Specify the Method used to identify the HCA:

 Method 1

*3. What is the PIR (Potential Impact Radius) for the location of this Incident?

/,/

 Method 2
/

/ feet

 Yes
 Yes
 Yes

*4. Were any structures outside the PIR impacted or otherwise damaged by heat/fire resulting from the Incident?
*5. Were any structures outside the PIR impacted or otherwise damaged NOT by heat/fire resulting from the Incident?
*6. Were any of the fatalities or injuries reported for persons located outside the PIR?
*7. Estimated Property Damage:
*7.a Estimated cost of public and non-Operator private property damage

/,/

*7.b Estimated cost of Operator’s property damage & repairs

/,/

*7.c Estimated cost of Operator’s emergency response

/,/

*7.d Estimated other costs

/,/

*7.f Estimated cost of gas released unintentionally

/,/

*7.g Estimated cost of gas released during
intentional and controlled blowdown

/,/

7.h Total estimated cost of gas released (sum of 7.f & 7.g above)

/,/

Describe ___________________________________________________
7.e Total estimated property damage (sum of above)
Cost of Gas Released

Form PHMSA F 7100.2 (Rev. xy-2012 )

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 No
 No
 No

PART E – ADDITIONAL OPERATING INFORMATION
*1. Estimated pressure at the point and time of the Incident (psig):

/,/

*2. Maximum Allowable Operating Pressure (MAOP) at the point and time of the Incident (psig) :

/,/

*3. 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 110% of MAOP
 Pressure exceeded 110% of MAOP
*4. Not including pressure reductions required by PHMSA regulations (such as for repairs and pipe movement), 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 4.a and 4.b below)

*4.a Did the pressure exceed this established pressure restriction?

 Yes

 No

*4.b Was this pressure restriction mandated by PHMSA or the State?

 PHMSA

 State

 Not mandated

*5. Was “Onshore Pipeline, Including Valve Sites” OR “Offshore Pipeline, Including Riser and Riser Bend” selected in PART C, Question 2?

 No
 Yes

 (Complete 5.a – 5.e below)

5.a Type of upstream valve used to initially isolate release source:

 Manual

5.b Type of downstream valve used to initially isolate release source:

 Manual  Automatic
 Check Valve

5.c Length of segment isolated between valves (ft):

/,/

 Automatic

 Remotely Controlled
 Remotely Controlled

5.d 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:__________________________________________________________________
5.e 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:__________________________________________________________________

5.f Function of pipeline system: (select only one)
 Transmission System
 Transmission Line of Distribution System
 Type A Gathering
 Type B Gathering
 Storage Gathering
 Offshore Gathering

Form PHMSA F 7100.2 (Rev. xy-2012 )

Page 7 of 20
Reproduction of this form is permitted

*6. Was a Supervisory Control and Data Acquisition (SCADA)-based system in place on the pipeline or facility involved in the Incident?
 No
 Yes  *6.a Was it operating at the time of the Incident?
 Yes
 No

 Yes
 No
*6.b Was it fully functional at the time of the Incident?
*6.c Did SCADA-based information (such as alarm(s), alert(s), event(s), and/or volume or pack calculations) assist with
the detection of the Incident?
 Yes
 No
*6.d Did SCADA-based information (such as alarm(s), alert(s), event(s), and/or volume calculations) assist with the
confirmation of the Incident?
 Yes
 No
*7. How was the Incident initially identified for the Operator? (select only one)

 SCADA-based information (such as alarm(s), alert(s), event(s), and/or volume or pack 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 _________________________________________________
*7.a If “Controller”, “Local Operating Personnel, including contractors”, “Air Patrol”, or “Ground Patrol by Operator or its contractor” is
selected in Question 7, specify the following: (select only one)

 Operator employee

 Contractor working for the Operator

*8. 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: ___________________________________________
_____________________________________________________________________________________________________
_____________________________________________________________________________________________________
_____________________________________________________________________________________________________

Form PHMSA F 7100.2 (Rev. xy-2012 )

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PART F – DRUG & ALCOHOL TESTING INFORMATION
*1. 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



*1.a Specify how many were tested:

*1.b Specify how many failed:

*2. 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



*2.a Specify how many were tested:

*2.b Specify how many failed:

Form PHMSA F 7100.2 (Rev. xy-2012 )

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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. Describe
secondary, contributing, or root causes of the Incident in the narrative (PART H).

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 _____________________________________________________________
*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 under the ground?
 Yes  *4.a Was failed item considered to be under cathodic protection at the time of
the incident?
 Yes  Year protection started: / / / / /

 No

*4.b Was shielding, tenting, or disbonding of coating evident at the point of
the incident?
 Yes  No
*4.c Has one or more Cathodic Protection Survey been conducted at
the point of the incident?
 Yes, CP Annual Survey  Most recent year conducted:
/ / /

 Yes, Close Interval Survey  Most recent year conducted: /
 Yes, Other CP Survey  Most recent year conducted:
/
 No
 No 

4.d Was the failed item externally coated or painted?

 Yes  No

*5. Was there observable damage to the coating or paint in the vicinity of the corrosion?
 Yes  No

 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 ____________ ________________________________________________
*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
 Other ____________________________________________________________
*10. Was the gas/fluid treated with corrosion inhibitors or biocides?
11. Was the interior coated or lined with protective coating?

 Yes  No

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. xy-2012 )

 No

Page 10 of 20
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Complete the following if any Corrosion Failure sub-cause is selected AND the “Item Involved in Incident” (from PART C, Question 3) is
Pipe or Weld.
14. Has one or more internal inspection tool collected data at the point of the Incident?
 Yes  No
14.a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run:

 Magnetic Flux Leakage Tool
 Ultrasonic
 Geometry
 Caliper
 Crack
 Hard Spot
 Combination Tool
 Transverse Field/Triaxial
 Other __________________________

15. Has one or more hydrotest or other pressure test been conducted since original construction at the point of the Incident?
 Yes  Most recent year tested: / / / / /
Test pressure (psig): /
/
/
/
/
/

 No

16. Has one or more Direct Assessment been conducted on this segment?
 Yes, and an investigative dig was conducted at the point of the Incident

 Yes, but the point of the Incident was not identified as a dig site
 No

 Most recent year conducted: /
 Most recent year conducted: /

17. Has one or more non-destructive examination been conducted at the point of the Incident since January 21, 2002?
 Yes  No
17.a If Yes, for each examination conducted since January 1, 2002, 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 __________________________

/
/
/
/
/
/

G2 - Natural Force Damage - *only one sub-cause can be picked from shaded left-hand column
 Earth Movement, NOT due to

*1. Specify:

Heavy Rains/Floods

 Earthquake  Subsidence  Landslide
 Other __________________

 Heavy Rains/Floods

2. Specify:

 Washout/Scouring  Flotation  Mudslide  Other _______________

 Lightning

3. Specify:

 Direct hit  Secondary impact such as resulting nearby fires

 Temperature

4. Specify:

 Thermal Stress
 Frozen Components

 Frost Heave
 Other ________________________________

 High Winds
 Other Natural Force Damage

*5. Describe: _________________________________________________

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?
*6.a If Yes, specify: (select all that apply)

 Yes

 No

 Hurricane  Tropical Storm
 Tornado
 Other ______________________________

Form PHMSA F 7100.2 (Rev. xy-2012 )

Page 11 of 20
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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 Questions 1-5 ONLY IF the “Item Involved in Incident” (from PART C,
Question 3) is Pipe or Weld.
*1. Has one or more internal inspection tool collected data at the point of the Incident?
 Yes  No
1.a If Yes, for each tool used, select type of internal inspection tool and indicate most
recent year run:

 Magnetic Flux Leakage
 Ultrasonic
 Geometry
 Caliper
 Crack
 Hard Spot
 Combination Tool
 Transverse Field/Triaxial
 Other _____________________

2. Do you have reason to believe that the internal inspection was completed BEFORE the
damage was sustained?  Yes  No
3. Has one or more hydrotest or other pressure test been conducted since original construction
at the point of the Incident?

 Yes 

Most recent year tested:
Test pressure (psig):

/
/

/
/, /

/
/

 No
4. Has one or more Direct Assessment been conducted on the pipeline segment?

 Yes, and an investigative dig was conducted at the point of the Incident
 Most recent year conducted: / / / / /
 Yes, but the point of the Incident was not identified as a dig site
 Most recent year conducted: / / / / /
 No
5. Has one or more non-destructive examination been conducted at the point of the Incident
since January 1, 2002?
 Yes  No
5.a If Yes, for each examination conducted since January 1, 2002, select type of nondestructive 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 __________________________

Complete the following if Excavation Damage by Third Party is selected as the sub-cause.
*6. Did the operator get prior notification of the excavation activity?
*6.a If Yes, Notification received from: (select all that apply)

 Yes  No
 One-Call System

Form PHMSA F 7100.2 (Rev. xy-2012 )

 Excavator

 Contractor

 Landowner

Page 12 of 20
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Complete the following mandatory CGA-DIRT Program questions if any Excavation Damage sub-cause is selected.
Yes

*7. Do you want PHMSA to upload the following information to CGA-DIRT (www.cga-dirt.com)?

 No

*8. 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
 Data not collected
 Unknown/Other

 Other

*9. Type of excavator: (select only one)

 Contractor
 Railroad

 County
 State

 Developer
 Utility

 Farmer
 Municipality
 Data not collected

 Occupant
 Unknown/Other

*10. Type of excavation equipment: (select only one)

 Auger
 Explosives
 Probing Device

 Backhoe/Trackhoe
 Farm Equipment
 Trencher

 Boring
 Grader/Scraper
 Vacuum Equipment

 Drilling
 Directional Drilling
 Hand Tools
 Milling Equipment
 Data not collected  Unknown/Other

*11. Type of work performed: (select only one)

 Agriculture
 Drainage
 Grading
 Natural Gas
 Sewer (Sanitary/Storm)
 Telecommunications
 Data not collected

 Cable TV
 Curb/Sidewalk
 Driveway
 Electric
 Irrigation
 Landscaping
 Pole
 Public Transit Authority
 Site Development
 Steam
Traffic Signal
 Traffic Sign
 Unknown/Other

*12. Was the One-Call Center notified?

 Yes

*12.a If Yes, specify ticket number: /

 Building Construction
 Engineering/Surveying
 Liquid Pipeline
 Railroad Maintenance
 Storm Drain/Culvert
 Water

 Building Demolition
 Fencing
 Milling
 Road Work
Street Light
 Waterway Improvement

 No
/

*12.b If this is a State where more than a single One-Call Center exists, list the name of the One-Call Center notified:
_____________________________________________________________
*13. Type of Locator:

 Utility Owner

 Contract Locator

 Data not collected

 Unknown/Other

 No

 Data not collected

 Unknown/Other

*14. Were facility locate marks visible in the area of excavation?

 No

*15. Were facilities marked correctly?

 No

*16. Did the damage cause an interruption in service?
*16.a If Yes, specify duration of the interruption:

 Yes
 Yes
 Yes

 Data not collected
 Data not collected

 Unknown/Other
 Unknown/Other

/___/___/___/___/ hours

(This CGA-DIRT section continued on next page with Question 17.)

*17. Description of the CGA-DIRT Root Cause (select only the one predominant first level CGA-DIRT Root Cause and then, where available
Form PHMSA F 7100.2 (Rev. xy-2012 )

Page 13 of 20
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as a choice, the one predominant second level CGA-DIRT Root Cause as well):

 *One-Call Notification Practices Not Sufficient: (select only one)
 No notification made to the One-Call Center
 Notification to One-Call Center made, but not sufficient
 Wrong information provided
 *Locating Practices Not Sufficient: (select only one)
 Facility could not be found/located
 Facility marking or location not sufficient
 Facility was not located or marked
 Incorrect facility records/maps
 *Excavation Practices Not Sufficient: (select only one)
 Excavation practices not sufficient (other)
 Failure to maintain clearance
 Failure to maintain the marks
 Failure to support exposed facilities
 Failure to use hand tools where required
 Failure to verify location by test-hole (pot-holing)
 Improper backfilling
 One-Call Notification Center Error
 Abandoned Facility
 Deteriorated Facility
 Previous Damage
 Data Not Collected
 Other / None of the Above (explain)____________________________________________________________________
____________________________________________________________________________________________________
____________________________________________________________________________________________________
____________________________________________________________________________________________________

Form PHMSA F 7100.2 (Rev. xy-2012 )

Page 14 of 20
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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

 Damage by Boats, Barges, Drilling
Rigs, or Other Maritime Equipment or
Vessels Set Adrift or Which Have
Otherwise Lost Their Mooring

*1. Vehicle/Equipment operated by: (select only one)
 Operator
 Operator’s Contractor

 Third Party

*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

Complete Questions 3-7 ONLY IF the “Item Involved in Incident” (from PART C,
Question 3) is Pipe or Weld.
3. Has one or more internal inspection tool collected data at the point of the Incident?
 Yes  No
3.a If Yes, for each tool used, select type of internal inspection tool and indicate most
recent year run:

 Magnetic Flux Leakage
 Ultrasonic
 Geometry
 Caliper
 Crack
 Hard Spot
 Combination Tool
 Transverse Field/Triaxial
 Other

4. Do you have reason to believe that the internal inspection was completed BEFORE the
damage was sustained?  Yes  No
5. Has one or more hydrotest or other pressure test been conducted since original construction
at the point of the Incident?

 Yes 

Most recent year tested:
Test pressure (psig):

/
/

/
/,/

/
/

 No
6. Has one or more Direct Assessment been conducted on the pipeline segment?

7. Has one or more non-destructive examination been conducted at the point of the Incident
Form PHMSA F 7100.2 (Rev. xy-2012 )

Page 15 of 20
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since January 1, 2002?
 Yes  No
7.a If Yes, for each examination conducted since January 1, 2002, select type of nondestructive 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 __________________________

 Intentional Damage

*8. Specify:

 Other Outside Force Damage

*9. Describe: _________________________________________________________

 Vandalism
 Terrorism
 Theft of transported commodity  Theft of equipment
 Other ________________________________________

Form PHMSA F 7100.2 (Rev. xy-2012 )

Page 16 of 20
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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)
 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:  Stress Corrosion Cracking
 Sulfide Stress Cracking
 Hydrogen Stress Cracking
 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 __________________________________

 Arc Burn  Crack
 Burnt Steel

*5. Has one or more internal inspection tool collected data at the point of the Incident?

 Lack of Fusion

 Yes  No

*5.a If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run:

 Magnetic Flux Leakage Tool
/
 Ultrasonic
/
 Geometry
/
 Caliper
/
 Crack
/
 Hard Spot
/
 Combination Tool
/
 Transverse Field/Triaxial
/
 Other __________________________ /

*6. Has one or more hydrotest or other pressure test been conducted since original construction at the point of the Incident?
 Yes  *Most recent year tested: / / / / /
*Test pressure (psig): /
/
/,/
/
/
/

 No

*7. Has one or more Direct Assessment been conducted on the pipeline segment?
 Yes, and an investigative dig was conducted at the point of the Incident

 Yes, but the point of the incident was not identified as a dig site
 No

 Most recent year conducted:
 Most recent year conducted:

*8. Has one or more non-destructive examination(s) been conducted at the point of the Incident since January 1, 2002?
 Yes  No
*8.a If Yes, for each examination conducted since January 1, 2002, 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 ________________________________

/
/
/
/
/
/

Form PHMSA F 7100.2 (Rev. xy-2012 )

Page 17 of 20
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G6 - Equipment Failure - *only one sub-cause can be picked from shaded left-hand column
 Malfunction of Control/Relief
Equipment

 Compressor or Compressor-related
Equipment

 Threaded Connection/Coupling

*1. Specify: (select all that apply)
 Control Valve
 Instrumentation
 SCADA
 Communications  Block Valve
 Check Valve
 Relief Valve
 Power Failure
 Stopple/Control Fitting
 Pressure Regulator
 ESD System Failure
 Other ________________________________________________________
*2. Specify:  Seal/Packing Failure
 Body Failure
 Crack in Body
 Appurtenance Failure
 Pressure Vessel Failure
 Other _______________________________________________________
3. Specify:

Failure

 Non-threaded Connection Failure

*4. Specify:

 Pipe Nipple
 Valve Threads
 Mechanical Coupling
 Threaded Pipe Collar  Threaded Fitting
 Other _______________________________________________________
 O-Ring
 Gasket
 Seal (NOT compressor seal) or Packing
 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
 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
 Other _______________________________________________________

Form PHMSA F 7100.2 (Rev. xy-2012 )

Page 18 of 20
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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

*1. Specify:

Vessel, or Cavern Allowed or
Caused to Overpressure

 Valve Misalignment  Incorrect Reference Data/Calculation
 Miscommunication
 Inadequate Monitoring
 Other ____________________________________

 Valve Left or Placed in Wrong
Position, but NOT Resulting in an
Overpressure
 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

*5.a 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:
___________________________________________________________________________
___________________________________________________________________________
*2. Specify:

 Unknown

 Investigation complete, cause of Incident unknown
 Still under investigation, cause of Incident to be determined*
(*Supplemental Report required)

Form PHMSA F 7100.2 (Rev. xy-2012 )

Page 19 of 20
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PART H – NARRATIVE DESCRIPTION OF THE INCIDENT

(Attach additional sheets as necessary)

__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
__________________________________________________________________________________________________________________
*PART I – PREPARER AND AUTHORIZED SIGNATURE

*Preparer's Name (type or print)

Preparer’s Telephone Number

Preparer's Title (type or print)

Preparer's E-mail Address

Preparer’s Facsimile Number

Authorized Signature

*Date

*Authorized Signature Telephone Number

*Authorized Signature’s Name (type or print)

Authorized Signature’s E-mail Address

Authorized Signature’s Title (type or print)

Form PHMSA F 7100.2 (Rev. xy-2012 )

Page 20 of 20
Reproduction of this form is permitted

Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

GENERAL INSTRUCTIONS
Each operator of a gas transmission or 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. 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 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).
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
incident 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. This situation is particularly susceptible to confusion as compared to other Natural or
Other Outside Force Damage because it is extremely difficult in most cases to establish whether
and which consequences were attributable to the initiating fire (that is, the “secondary ignition”
source itself) or to a subsequent fire due to a resulting pipeline system failure or release.
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 $50,000.
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,
then select Data, Reports & Library, and then select Forms under the “Mini-Menu” on the right

Page 1 of 30

Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

side of the page. The applicable forms are listed in the section titled Accident/Incident/Annual
Reporting Forms.

ONLINE REPORTING REQUIREMENTS
Incident Reports must be submitted online through the PHMSA Portal at
https://portal.phmsa.dot.gov/pipeline, 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
http://opsweb.phmsa.dot.gov/portal_message/PHMSA_Portal_Registration.pdf
Completing these registration requirements could take several weeks. Plan ahead and register
well in advance of the report due date.

1.
Use the following procedure for online reporting:

Go to to the PHMSA Portal at https://portal.phmsa.dot.gov/pipeline

2. Enter PHMSA Portal Username and Password ; press enter
3. Select OPID ; press “continue” button.
4. On the left side menu under “Incident/accident” select “ODES 2.0”

5. Under “Create Reports” on the left side of the screen, select “Gas Transmission and
Gathering Incident Report” and proceed with entering your data. Note: Data fields
marked with a single asterisk are considered required fields that must be completed
before the system will accept your initial submission.
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 return you to the initial view of the screen that
lists your [Saved Incident/Accident Reports] in the top portion of the screen and your

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Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

[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 select a previously
submitted report from the [Submitted Incident/Accident Reports] list in the bottom portion of the
screen by double clicking on the desired report. The report will default to a “Read Only” mode
that is pre-populated with the data you entered 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 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. Reports that were saved will appear in the [Saved
Incident/Accident Reports] list in the top portion of the screen and reports that were submitted
will appear in the [Submitted Incident/Accident Reports] list in the bottom portion of the screen.
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 30day 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 30

Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

SPECIAL INSTRUCTIONS
Certain data fields must be completed before an Original Report will be accepted. The data
fields that must be completed for an Original Report to be accepted are indicated on the online
form. 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. For questions requiring numeric answers, all preceding and/or unused data fields should be
filled in using zeroes. When decimal points or commas are required and not already shown in
the data field, the decimal point or comma should be placed in a separate block in the
data field.
Examples:
(PART C, Question 3.a, ) Nominal diameter of pipe (in):
(PART C, Question 3.b), Wall thickness (in)
(PART C, Question 3.c), SMYS

/0/0/2/4/ (24 inches)
/3/./5/
(3.5 inches)
/0/./3/1/2/ (0.312 inches)
/0/5/2/,/0/0/0/ (52,000 psi)

7. 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.
8. Pay close attention to each question for the phrase:
a. (select all that apply)
b. (select only one)

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Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

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.
9. Date format = mm/dd/yy or for year = /yyyy/
10. Time format: All times are reported as a 24-hour clock:
Time format Examples:
a. (0000) = midnight =
b. (0800) = 8:00 a.m. =
c. (1200) = Noon
=
d. (1715) = 5:15 p.m. =
e. (2200) = 10:00 p.m. =

/0/0/0/0/
/0/8/0/0/
/1/2/0/0/
/1/7/1/5/
/2/2/0/0/

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

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Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

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 not to exceed $100,000 for each violation for each day
that such violation persists up to a maximum of $1,000,000.

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.

In PART A, answer Questions 1 thru 19 by providing the requested
information or by making the appropriate selection.
1. 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 202366-8075 if you need assistance with an OPID. Business hours are 8:30 AM to 5:00 PM Eastern
Time.

2. Name of Operator

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Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

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.
3. 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.
4. Local time (24-hour clock) and date of the Incident
Enter the earliest local date/time a reporting criteria was met. In some cases, this date/time must
be estimated based on information gathered during the investigation..
See “Special Instructions”, numbers 9 and 10 for examples of Date format and Time format
expressed as a 24-hour clock.
5. 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://www.getlatlon.com/ or 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]).

6. National Response Center (NRC) Report Number

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Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

§191.5 requires that incidents meeting the criteria outlined in §191.3 be reported directly to the
24-hour National Response Center (NRC) at 1-800-424-8802 at the earliest practicable
moment (generally within 2 hours). The NRC assigns numbers to each call. The number
assigned to that Immediate Notice (sometimes referred to as the “Telephonic Report”) is to be
entered in Question 6.
7. Local time (24-hr clock) and date of initial telephonic report to the National Response
Center
Enter the time and date of the 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.)
8. Incident resulted from
Indicate whether the incident resulted from the intentional or unintentional release of gas or for
reasons other than a release of gas.
9. Gas released
Select the type of gas released. Examples of Synthetic Gas include landfill gas, biogas, and
manufactured gas based on naphtha.

Important Note for Questions 10, 12, and 12: Volumes consumed by fire and/or explosion are to
be included in the estimated volumes reported.
10. 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 best-available information.
11. 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 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.
12. Estimated volume of accompanying liquid released

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Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

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. De minimus 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

13. 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.)
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”.
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-ofway 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”.
14. 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.

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Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

See Question 13 for additional definitions that apply.
15. Was the pipeline/facility shut down due to the Incident?
Report any shutdowns that occur as a result of the incident, including but not limited to those
required for damage assessment, temporary repair, permanent repair, and clean-up.
If No is selected, explain the reason that no shutdown was needed in the space provided.
If Yes is selected, complete Questions 15.a and 15.b.
15.a. Local time (24hr clock) and date of shutdown
15.b. Local time pipeline/facility restarted
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 15.a. The affected
facilities may still contain gas at this time. Enter the time and date of restart in 15.b. 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
15.b and then include the restart time and date in a future Supplemental Report.
16. Did the gas ignite?
Ignite means the released gas caught fire.
17. Did the gas explode?
Explode means the ignition of the released gas occurred with a sudden and violent release of
energy.
18. 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). If an estimate is not possible for some reason, leave the field
blank but include an explanation of why it was not possible to provide a number in PART H –
Narrative Description of the Incident.
19. Time sequence (use local time, 24-hour clock)
In 19a, enter the date/time the operator became aware of the incident, NOT when the operator
determined that the incident met the reporting criteria of §191.3. In 19b, enter the date/time
operator responders, company or contract, arrived on site. The time is to be shown by 24-hour

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Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

clock notation and reported in the time zone where the incident occurred. (See “Special
Instructions”, numbers 9 and 10.)

PART B – ADDITIONAL LOCATION INFORMATION
1. Was the origin of the incident onshore?
Answer Yes or No as appropriate and complete only the designated questions.
If Onshore
2. – 5. Incident Location
Provide the state, zip code, city, and county/parish in which the incident occurred.
6. 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/valve station or survey station
number. This designator is intended to allow PHMSA personnel to both return to the physical
location of the incident using the operator’s own maps and identification systems as well as to
identify the “paper” location of the incident when reviewing operator maps and records.
7. 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”.

8. 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”.
9. 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

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Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

other Federal office buildings and warehouses, are NOT to be reported as being on Federal
Lands.
10. 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.
11. 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 stained 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.

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, 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.
12. Did Incident occur in a crossing?
Use Bridge Crossing if the pipeline is suspended above a body of water or roadway, railroad
right-of-way, etc. either on a separately designed pipeline bridge or as a part of or connected to a
road, railroad, or passenger bridge.

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Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

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 Offshore
13. 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).

14. Origin of the Incident
Area and Tract/Block numbers are to be provided for either State or OCS waters, whichever is
applicable.
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.

PART C – ADDITIONAL FACILITY INFORMATION
1. Is the pipeline or facility [Interstate or Intrastate]?

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Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

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.).
3. 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 diameter of pipe is also called Nominal pipe size. It is the diameter in whole number
inches (except for pipe less than 4”) 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
4”).
Enter pipe wall thickness in inches. Wall thickness is typically less than an inch, and is
standard among different pipeline types and manufacturers. Accordingly, use three decimal
places to report wall thickness: 0.312, 0.281, etc.
SMYS means specified minimum yield strength and is the yield strength prescribed by the
specification under which the material is purchased from the manufacturer.
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
Auxiliary piping means piping, usually small in diameter, that supports the operation of the
mainline or facility piping, but does not include tubing. Examples of auxiliary piping include
discharge and drain lines, etc.
If the incident occurred on an item not provided in this section, select “Other” and specify the
item that failed in the space provided.
6. Type of Incident involved (select only one)

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Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

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.
Rupture means the pipeline facility has burst, split, or broken and the operation of the pipeline
facility is immediately impaired. Pipeline ruptures often result in a higher flow release of larger
volume. The terms “circumferential” and “longitudinal” refer to the general direction or
orientation of the rupture relative the pipe’s axis. They do not exclusively refer to a failure
involving a circumferential weld such as a girth weld, or to a failure involving a longitudinal
weld such as a pipe seam. (Precise measurement of size – e.g., micrometer – is not needed.
Approximate measurements can be provided in inches and decimals.)

PART D – ADDITIONAL CONSEQUENCE INFORMATION
§ 192.903 What definitions apply to this subpart?
*

High consequence area means an area established by one of the methods described in
paragraphs (1) or (2) as follows:
(1) An area defined as-(i) A Class 3 location under Sec. 192.5; or
(ii) A Class 4 location under Sec. 192.5; or
(iii) Any area in a Class 1 or Class 2 location where the potential impact radius is
greater than 660 feet (200 meters), and the area within a potential impact circle
contains 20 or more buildings intended for human occupancy; or
(iv) Any area in a Class 1 or Class 2 location where the potential impact circle
contains an identified site.
(2) The area within a potential impact circle containing-(i) 20 or more buildings intended for human occupancy, unless the exception in
paragraph (4) applies; or
(ii) An identified site.

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Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

(3) Where a potential impact circle is calculated under either method (1) or (2) to
establish a high consequence area, the length of the high consequence area extends axially
along the length of the pipeline from the outermost edge of the first potential impact circle
that contains either an identified site or 20 or more buildings intended for human
occupancy to the outermost edge of the last contiguous potential impact circle that contains
either an identified site or 20 or more buildings intended for human occupancy. (See figure
E.I.A. in appendix E.)
*

2. 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.
2.a. 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.
3. 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.
PIR is defined in §191.903 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.
[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.]

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Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

4. 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.
5. 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.
6. Were any of the fatalities or injuries reported for persons located outside the PIR?
This refers to the fatalities and injuries reported in PART A, Questions 13 and 14.
7. 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 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.
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.
Operator’s property damage estimates generally include physical damage to the property of
the operator or owner company such as the estimated installed or replacement value of the

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INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

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, 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.
Estimated cost of Operator’s 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. Costs related to stakeholder outreach, media response,
etc. are not to be included.
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
Cost of gas released unintentionally is to be based on the volume reported in
PART A, Question 10.
Cost of gas released during intentional and controlled blowdown is to be based
on the volume reported in PART A, Question 11.

PART E – ADDITIONAL OPERATING INFORMATION
4. Not including pressure reductions required by PHMSA regulations (such as for repairs
and pipe movement), 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 directed by an order or other

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Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

formal correspondence. Pressure reductions imposed by the operator as a result of regulatory
requirements, e.g., a pressure reduction taken because an anomaly identified during an IM
assessment could not be repaired within the required schedule (§192.933(d)), is not to be
considered mandated by PHMSA.
5.a. Type of upstream valve used to initially isolate release source
Identify the type of valve used to initially isolate the release on the upstream side. In general,
this will be the first upstream 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.
5.b. Type of downstream valve used to initially isolate release source
Identify the type of valve used to initially isolate the release on the downstream side. In general,
this will be the first 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.
5.c. Length of segment isolated between valves (ft)
Identify the length in feet between the valves identified in Questions 5.a and 5.b that were
initially used to isolate the incident area.
5.f. 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 and Type B 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 or Type B in
§192.8.
Offshore Gathering means a gas gathering pipeline located offshore.
Storage Gathering means a transmission pipeline that transports gas within a storage field.
6. 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.
6.a. Was it operating at the time of the Incident?

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INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

Was the SCADA system in operation at the time of the incident?
6.b. 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.
6.c and d. Did SCADA-based information (such as alarm(s), alert(s), event(s),
and/or volume or pack calculations) assist with the detection or confirmation 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.
7. How was the Incident initially identified for the Operator? (select only one)
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.
8. 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.

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Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

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.

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 sub-cause, and describe any secondary, contributing, or root
causes of the Incident in PART H – Narrative Description of the Incident.

G1 – Corrosion Failure
Corrosion includes a release or failure caused by galvanic, atmospheric, stray current,
microbiological, 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
4.a. 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.

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INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

4.b. Type of corrosion – 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.

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?
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.
Either External or Internal Corrosion
14.a. If Yes, for each tool used, select type of internal inspection tool and indicate most
recent year run
Magnetic Flux Leakage Tool is an in-line inspection tool using an imposed magnetic flux to
detect instances of pipe wall loss from corrosion. This includes low- and high-resolution MFL
tools. It does not include transverse flux MFL tools, which are a separate choice in this question.
Ultrasonic refers to an in-line inspection tool that uses ultrasonic technology to measure wall
thickness and detect instances of wall loss.
Transverse Field/Triaxial tools are specialized magnetic flux leakage tools that use a flux
oriented to improve ability to detect crack anomalies.
Combination Tool refers to any in-line inspection tool that uses a combination of these
inspection technologies in a single tool.
15. 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 to be reported.

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Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

16. Has one or more 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.

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. (See also the discussion of “secondary ignition” under the General
Instructions.)
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.

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INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

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.
1.a. If Yes, for each tool used, select type of internal inspection tool and indicate most
recent year run

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INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

Magnetic Flux Leakage Tool is an in-line inspection tool using an imposed magnetic flux to
detect instances of pipe wall loss from corrosion. Includes low- and high-resolution MFL tools.
Does not include transverse flux MFL tools, which are a separate choice in this question.
Ultrasonic refers to an in-line inspection tool that uses ultrasonic technology to measure wall
thickness and detect instances of wall loss.
Transverse Field/Triaxial tools are specialized magnetic flux leakage tools that use a flux
oriented to improve ability to detect crack anomalies.
Combination Tool refers to any in-line inspection tool that uses a combination of these
inspection technologies in a single tool.
3. 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 to be reported.
4. Has one or more 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 were not used as part of the direct assessment process defined in
§192.903 do not constitute a Direct Assessment for purposes of this question.
6. – 17. Complete these questions for any excavation damage sub-cause. Instructions for
answering
these
questions
can
be
found
at
CGA’s
web
site,
https://www.damagereporting.org/dr/control/userGuide.do.

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

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AND GATHERING PIPELINE SYSTEMS

(see below). This sub-cause is NOT to be used if the release occurred first and then the gas
released from the pipeline system or facility ignited.
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, grading, cultivation or
similar excavation activities, report under G3 - Excavation Damage.
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, 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

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INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

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.)
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.

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 subcause 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 faulty manufacturing procedures, defects
resulting from poor construction, installation, or fabrication practices, and in-service stresses
such as vibration, fatigue, and environmental cracking.
Construction-, Installation-, or Fabrication-related includes a release or failure caused by a
dent, gouge, excessive stress, or some other defect or anomaly introduced during the process of
constructing, installing, or fabricating pipe and pipe welds, including welding or other activities
performed at the facility. Included are releases from or failures of wrinkle bends, field welds,

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AND GATHERING PIPELINE SYSTEMS

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).
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 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.
Environmental Cracking-related includes failures by Stress Corrosion Cracking, Sulfide Stress
Cracking, Hydrogen Stress Cracking or other environmental cracking mechanism.
If Construction-, Installation-, or Fabrication-related, or Original Manufacturing-related is
selected, then select any contributing factors. Examples of Mechanical Stress include failures
related to overburden or loss of support.

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, 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

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Incorrect Operation includes a release or failure resulting from operating, maintenance, repair,
or other errors by facility personnel, including, but not limited to improper valve selection or
operation, inadvertent overpressurization, or improper selection or installation of equipment.
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.
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.

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.

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Instructions (rev xy-2012) for Form PHMSA F 7100.2 (rev xy-2012)
INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION
AND GATHERING PIPELINE SYSTEMS

Use this section to clarify or explain unusual conditions, to provide sketches or drawings, and to
explain any estimated data. Operators submitting reports on-line will be afforded the opportunity
to attach/upload files (in PDF or JPG format only) containing sketches, drawings, or additional
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.

PART I – PREPARER AND AUTHORIZED SIGNATURE
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.
An Authorized Signature must be obtained from an officer, manager, or other person whom the
operator has designated to review and approve the report. This individual 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 individual signing as the Authorized
Signature.

Page 30 of 30

File Type	application/pdf
Author	PHMSA
File Modified	2012-12-05
File Created	2012-12-05