Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012)

INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

Page 1 of 30

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/library/forms. The applicable documents are listed in the section 

titled Accident/Incident/Annual Reporting Forms.
Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012)

INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

Page 2 of 30

ONLINE REPORTING REQUIREMENTS

Incident Reports must be submitted online through the PHMSA Portal at 

https://portal.phmsa.dot.gov/portal, unless an alternate method is approved (see Alternate Reporting 

Methods below). You will not be able to submit reports until you have met all of the Portal 

registration requirements – see 

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.

Use the following procedure for online reporting:

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

2. Enter PHMSA Portal Username and Password ; press enter

3. Select OPID; press “continue” button.

4. On the left side menu under “Incident/accident” 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 

[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 
Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012)

INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

Page 3 of 30

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 30-

day written report) and upon subsequent investigation determines that the event did not meet the 

criteria in §191.3 may request that the report be retracted. Requests to retract a 30-day written 

report are to be emailed to InformationResourcesManager@dot.gov. 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”).
Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012)

INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

Page 4 of 30

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): /0/0/2/4/ (24 inches)

 /3/./5/ (3.5 inches)

 (PART C, Question 3.b), Wall thickness (in) /0/./3/1/2/ (0.312 inches)

 (PART C, Question 3.c), SMYS /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)

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 
Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012)

INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

Page 5 of 30

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 = /0/0/0/0/

b. (0800) = 8:00 a.m. = /0/8/0/0/

c. (1200) = Noon = /1/2/0/0/

d. (1715) = 5:15 p.m. = /1/7/1/5/

e. (2200) = 10:00 p.m. = /2/2/0/0/

Local time always refers to time at the site of the incident. Note that time zones at the 

incident site may be different than the time zone for the person discovering or reporting 

the event. For example, if a release occurs at an gas transmission facility in Denver, 

Colorado at 2:00 pm MST, but an individual located in Houston is filing the report after

having been notified at 3:00 pm CST, the time of the incident is to be reported as 1400 

hours based on the time in Denver, which is the physical site of the incident.

PART A – KEY REPORT INFORMATION

Report Type: (select all that apply)

Select the appropriate report box or boxes to indicate the type of report being filed. Depending 

on the descriptions below, the following combinations of boxes – and only one of these 

combinations - may be selected:

• Original Report only

• Original Report plus Final Report

• Supplemental Report only

• Supplemental Report plus Final Report

 Original Report

 

Select if this is the FIRST report filed for this incident and you expect that additional or updated 

information will be provided later.

 Original Report plus  Final Report

Select both Original Report and Final Report if ALL of the information requested is known and 

can be provided at the time the initial report is filed, including final property damage costs and 

apparent failure cause information. If new, updated, and/or corrected information becomes 

available, you are still able to file a Supplemental Report.
Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012)

INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

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 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 202-

366-8075 if you need assistance with an OPID. Business hours are 8:30 AM to 5:00 PM Eastern 

Time.

2. Name of Operator

This is the company name associated with the OPID. For online entries, the name will 

automatically populate based on the OPID entered in A1. If the name that appears is not correct, 

you need to submit an Operator Name Change (Type A) Notification. 
Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012)

INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

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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 amy.nelson@dot.gov).

6. National Response Center (NRC) Report Number 

§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.
Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012)

INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

Page 8 of 30

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

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.
Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012)

INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

Page 9 of 30

If estimated volume 

is Report If estimated volume is Report

<5 gallons 0.1 barrels 24-27 gallons 0.6 barrels

5-10 gallons 0.2 barrels 28-31 gallons 0.7 barrels

11-14 gallons 0.3 barrels 32-35 gallons 0.8 barrels

15-18 gallons 0.4 barrels 36-39 gallons 0.9 barrels

19-23 gallons 0.5 barrels 40-42 gallons 1.0 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. 

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. 
Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012)

INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

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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 

clock notation and reported in the time zone where the incident occurred. (See “Special 

Instructions”, numbers 9 and 10.)
Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012)

INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

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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 

other Federal office buildings and warehouses, are NOT to be reported as being on Federal 

Lands.
Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012)

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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.

Use Railroad Crossing or Road Crossing, as appropriate, if the pipeline is buried beneath rail 

bed or road bed. 
Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012)

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AND GATHERING PIPELINE SYSTEMS

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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.
Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012)

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AND GATHERING PIPELINE SYSTEMS

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PART C – ADDITIONAL FACILITY INFORMATION

1. Is the pipeline or facility [Interstate or Intrastate]?

Interstate gas pipeline facility means a gas pipeline facility or that part of a gas pipeline facility 

that is used to transport gas and is subject to the jurisdiction of the Federal Energy Regulatory 

Commission (FERC) under the Natural Gas Act (15 U.S.C. 717 et seq.).

Intrastate gas pipeline facility means a gas pipeline facility or that part of a gas pipeline facility 

that is used to transport gas within a state and is not subject to the jurisdiction of FERC under the 

Natural Gas Act (15 U.S.C. 717 et seq.).

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.
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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)

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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 (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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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 

damaged pipe, coating, component, materials, or equipment due to the incident, excluding the
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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.
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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 

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.
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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?

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.
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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.

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 
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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.

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.
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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.

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.
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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. 

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 
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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

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 
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explosion or fire that originated at a neighboring facility or installation (chemical plant, tank 

farm, or other industrial facility) or structure, debris, or brush/trees that results in a release at the 

operator’s pipeline or facility. This includes forest, brush, or ground fires that are caused by 

human activity. If the fire, however, is known to have been started as a result of a lightning 

strike, the incident’s cause is to be classified under G2 - Natural Force Damage. Arson events 

directed at harming the pipeline or the operator are to be reported as G4 - Intentional Damage 

(see below). 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.
Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012)

INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

Page 27 of 30

Previous Mechanical Damage NOT Related to Excavation. This sub-cause covers incidents 

where damage occurred at some time prior to the release that was apparently NOT related to 

excavation activities, and would include prior outside force damage of an unknown nature, prior 

natural force damage, prior damage from other outside forces, and any other previous 

mechanical damage other than that which was apparently related to prior excavation. Incidents 

resulting from previous damage sustained during construction, installation, or fabrication of the 

pipe or weld from which the release eventually occurred are to be reported under G5 - Material 

Failure of Pipe or Weld. (See this sub-cause for typical indications of previous construction, 

installation, or fabrication damage.) Incidents resulting from previous damage sustained as a 

result of excavation activities should be reported under G3 – Previous Damage due to Excavation 

Activity. (See this sub-cause for typical indications of prior excavation activity.)

Intentional Damage

Vandalism means willful or malicious destruction of the operator’s pipeline facility 

or equipment. This category would include arson, pranks, systematic damage 

inflicted to harass the operator, motor vehicle damage that was inflicted 

intentionally, and a variety of other intentional acts. (See also the discussion of 

“secondary ignition” under the General Instructions.) 

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. 
Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012)

INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

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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, 

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.
Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012)

INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

Page 29 of 30

G7 – Incorrect Operation

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.
Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012)

INCIDENT REPORT – NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

Page 30 of 30

PART H – NARRATIVE DESCRIPTION OF THE INCIDENT

Concisely describe the incident, including the facts, circumstances, and conditions that may have 

contributed directly or indirectly to causing the incident. Include secondary, contributing, or root

causes when possible, or any other factors associated with the cause that are deemed pertinent. 

Use this section to clarify or explain unusual conditions, 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.