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 d etection 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 un der “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 Part s 191 or 192, such as e lectrical 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 Part s 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” i ncidents):

• 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 fail ure or release, or would have occurred whether or not the pipeline

system fail ure 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 , u nless 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 requi rements

– see http://opsweb.phmsa.dot.gov/portal_message/PHMSA_Portal_Registration.pdf Completing these registration requirements could take several week s . 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 Pas sword ; press enter

3. Select OPID; press “ continue ” button.

4. O n 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 complet ed before the system will accept your initial submission

.

6. Click “ S ubmit ” when finished with your data entry to have y our 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 d ata 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 you r report was successfully submitted to PHMSA, look for it in the bottom portion of the scree n where you can also view a PDF of what you submitted.

Supplemental Report Filing

– F ollow S teps 1 through 4 above

, and then select a previously

submitted report from the [Submitted Incident/Accid ent Reports] list i n 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 S upple mental 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 aInstructions (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 Fin al Report (see “Specific Instructions,

P ART 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.

Alterna te 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.



## RE TRACTING 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 email ed to InformationResourcesManager@dot.gov

. Requests are to include the following information:

a. The Report ID ( the unique 8

- digi t identifier assigned by PHMSA )

b. Operator name

c. PHMSA

- issued OP ID number

d. The number assigned by the Nation al Response Center (NRC) when a n immediate notice was made in accordance with § 191.5

. If S upplemental

R eports were made to the NRC for the ev ent, 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 

## S PECIAL 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. Y our 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 “ U nknown” for text fields and leave numeric fields and fields using check boxes or “radio” buttons blank.

3. Estimate data only if necessary. P rovide an estimate in lieu of answering a question with

“ U nknown” 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 S upplemental R eport 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 actu al 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 d ecimal 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) (P ART C, Qu estion 3.b), Wall thickness (in) /0/

. /3/1/2/ (0.312 inches) (P ART 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 “ O ther” 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 applicableInstructions (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 s ite 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 a n 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 Rep ort

• 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

Page 6 of 30  Supplemental Report

Select only if you have already filed an Original Report AND you are now providing new, updated, and/or corrected information. Multiple S upplement al Report s 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 thes e 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 dat a previously submitted will automatically populate in the form. Page through the form to make edits and additions where needed.

 Supplemental Report plus  Final Report

I f 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 subsequen tly find that new , updated, and/ or corrected information needs to be provided, submit another Supplemental Report

.



### In P ART A, answer Q uestions 1 thru 19 by providing the requested information or by making the appropriate select ion

.

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. B usiness hours are 8:30 AM to 5:00 PM Eastern

Time

.

2. Name of Operator

This is the company name associated with the OP ID. For online entries, the name will automatically populate based on the OPID entered in A 1. 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

Page 7 of 30 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 Inciden t

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”, number s 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 i n 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 tool s 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 i ncidents 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 I mmediate N otice (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 t ime (24

- hr clock) and d ate of i nitial t elephonic r eport to the National Response

Center

Enter the time and date of the I mmediate N otice 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 easter n time zone. (S ee “ Special Instructions”, numbers 9 and 10 .)

8. Incident resulted from

Indicate whether the incident resulted from the intentional or unintentional release of gas or f or reasons other than a release of gas.

9. Gas released

Select the type of gas released. Examples of S ynthetic G as include landfill gas, biogas, and manufactured gas based on nap h tha.

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 v olume 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 o r 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 o perator su ch 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 t he 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 2 4

- 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

- 2 3 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

- O perator e mergency r esp onders 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 “G eneral 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 righ t

- of

way including work associated with other underground facilities sharing the right

- of

- way, building/road construction in or across the right

- of

- way, or farming. This category most often includes employees of other pipelines or underground facilities o perators, 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 “G eneral 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 s hut down due to the I ncident ?

Report any shutdowns that occur as a result of the in cident

, 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

Page 10 of 30 If No is selected, explain the reason that no shutdown was needed in the space provided.

If Yes is selected, complete Q uestions 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 in cident was physically located. (S ee “ 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

1 5 .b and then include the restart time and date in a future Supplemental Report.

16. Did the gas i gnite ?

Ignite means the released gas caught fire

.

17. Did the gas e xplode ?

Explode means the ignition of the released gas occurred with a sudden and violent release of

energy.

18. Number of g eneral p ublic e vacuated

The number of people evacuated is to be estimated based on operator knowledge, or police, fire department

, or other emerge ncy 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 P ART H

– Narrative Description of the Incident.

19. Time sequence (use local time, 24

- hour clock)

In 19a, e nter 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 in cident occurred . (S ee “ 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

Page 11 of 30 

### PART B

– ADDITIONAL LOCATION INFORMATION

1. Was the origin of the incident onshore?

Answer Y es or N o 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

- d esignated l ocation

This is intended to be the designation that the operator would use to identify the location of the

i ncident 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 i ncident using the operator’s own maps and identification systems as well as to identify the “paper” location of the i ncident when reviewing operator maps and records.

7. Pipeline/Facility n ame

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 i ncident occurred, for example, the “West Line 24” Pipeline”, or “Gulf Coast Pipeline” , or “Wooster Storage Facility”

.

8. Segment name/ID

Within a given pip eline 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 examp le, “Segment 4

- 32”, or “MP 4.5 to Wayne County Line”, or “Dublin Compressor Station”, or “Witte Reducing Station”.

9 . Was the I ncident 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. Incident s at Federal buildings, such as Federal Court Hou ses, 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)

INCIDENT REPORT

– NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

Page 12 of 30 10 . Location of I ncident

Operator

- controlled Property would normally apply to a n operator’s facility, which may or may not have co ntrolled 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)

T his 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 damag e. 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 exa mination . 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 nat ural 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),

an other 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)

INCIDENT REPORT

– NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

Page 13 of 30 Use Water Crossing if the pipeline is in the water, beneath the water, in contact with the natural

gro und 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 u nderstood 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 comm only 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 w ater d epth (ft) of the lak e, 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 w ater d epth (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 Q uestion 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 i s 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)

INCIDENT REPORT

– NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

Page 14 of 30 

### 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.)

.

I ntrastate gas pipeline facility means a gas pipeline facility or that part of a gas pipeline facility that is used to transport gas within a s tate 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

AS TM 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 electr ic

- 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

.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 15 of 30 If the incident occurred on an it em not provided in this section, select “ Other ” and specify the

item that failed in the space provided.

6 . Type of Incident i nvolved ( select only one )

Mechanical puncture means a puncture of the pipeline , typically by a piece of equipment such

as would o ccur 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 m easurements 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 o ccasion.

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 “longit udinal” 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 s eam. (Precise measurement of size

– e.g., micrometer

– is not needed. Approximate m easurements 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 C lass 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.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 16 of 30 (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 outerm ost 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 I ntegrity M anagement (IM) P rogram 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 d efinition 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 * d 2

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 th e 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 S ection 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. ]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 17 of 30 4

. Were any structures outside the PIR impacted or otherwise damaged by heat/fire resulting from the I ncident?

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/f ire resulting from the I ncident ?

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 P ART A, Q uestions 13 and 14.

7 . Estimated Property Damage

All relevant costs available at the time of submission must be included on the initial written

I ncident R eport as well as being updated as needed on S upplemental R eports. 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 . A dditionally, do NOT include costs incurred for facility repair, replacement, or change s 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

fac ilities unearthed because of the incident . Litigation and other legal expenses related to the

i ncident 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, t his estimate can be revised

, if needed, when S upplemental R eports are filed for other reasons , however, when no other changes are forthcoming, S upplemental R eports are to be filed as new cost information becomes

available. If S upplemental R eports are not submitted for other reasons , a S upplemental R eport is

to be filed for the purpose of updating or correcting the estimated cost if these costs differ from those already reported by 2 0 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 o perator , 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 o perator or o wner c ompany such as the estimated installed or replacement value of t he damaged pipe, coating, component, materials

, or equipment due to the i ncident

, excluding theInstructions (rev 12

- 2012) for Form PHMSA F 7100.2 (rev 12

- 2012)

INCIDENT REPORT

– NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

Page 18 of 30 cost of any gas lost. Also to be excluded are litigation and other legal expenses related to the

incident

.

When estimating the Cost of r epairs 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

nece ssary 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 improv ements 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 e mergency r esponse include s 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 an y 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 cat egories 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

P ART A, Question 10.

Cost of gas released during intentional and controlled blowdown is to be based on the volume reported in P ART A, Question 11.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 19 of 30 

### 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 ?

Consi der 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 resul t 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 o perator to minimize the release volume but may not be the c losest 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 relea se on the downstream side . In general, this will be the first downstream valve selected by the o perator 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 relea se 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 S ystem 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 par t 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 produ ction facility to a transmission line or main and that meets the criteria for either Type A or Type B in § 192.8

.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 20 of 30 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 i ncident ?

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 i t was actually in operation at the time of the incident ? If N o, 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 Y es if S CADA

- 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 identifica tion of

the incident.

7

. How was the I ncident 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 accountabil ity 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

.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 21 of 30 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 I ncident ?

Select only one of the choices to indicate whether an investigation was/is being conducted (Yes) or was not conducted (No). If an investi gation 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 indicati ve 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 includ e 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 N o. 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

S elect the one, single sub

- cause listed under sections G1 thru G8 that best describes the apparent cause of the I n cident . Thes e 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, contri buting, or root

causes of the I n cident in PART H

– Narrative Description of the Incident

.

G 1

– 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 onInstructions (rev 12

- 2012) for Form PHMSA F 7100.2 (rev 12

- 2012)

INCIDENT REPORT

– NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

Page 22 of 30 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 d rop 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) rout inely utilized?

13. Were corrosion coupons routinely utilized?

For purposes of these Q uestions 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 ensu re that

water build

- up and/or settling and internal corrosion do not occur.

Either External or Internal Corrosion

1 4.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 i ncludes low

- and high

- resolution MFL

tools. It d oes not include transverse flux MFL tools, which are a separate choice in this quest ion.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 23 of 30 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 impr ove 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.

1 5 . Has one or more hydrotest or other pressure test been conducted since original

c onstruction at the point of the I ncident?

Information from the initial post

- construction hydrostatic test is not to be reported.

1 6 . Has one or more Direct Assessment been conducted on this segment?

This refers to direct assessment as defined in § 19 2.9 03 . 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 § 19 2.903 do NOT constitute a Direct Assessment for purposes of this question.

G 2

– Natural Force Damage

Natural Force Damage includes a release or failure resulting from earth movement, earthquakes, landslides, subsidence, lightning, heavy rains/floods, washouts, fl otation, 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 no t mudslides which are presumed to be initiated by heavy rains or floods

.

Heavy R ains / F loods 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

e ffect 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 initia ting 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.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 24 of 30 Frozen component s 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 O utside F orce D amage

.

Other Natural Force Damage. Select this sub

- cause for types of Natural Force Damage not included otherwise, and d escribe in the space provided . I f necessary, provide additional explanation in P ART 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 relate d to something other than a hurricane, tropical storm, or tornado w as involved, indicate Other and

describe the event in the space provided.

G 3

– 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 referr ed 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, f or 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 G 4 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 Operat or’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 result ed 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/orInstructions (rev 12

- 2012) for Form PHMSA F 7100.2 (rev 12

- 2012)

INCIDENT REPORT

– NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

Page 25 of 30 testing me thods. 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 MF L 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 Fi eld/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 sing le 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 Asse ssment 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 const itute a Direct Assessment for purposes of this question.

6

. – 1 7

. 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

.

G 4

– Other Outside Force Damage

Other O utside F orce D amage 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 C ause of Incident applies

to situation s where the fire occurred before

- and caused

- the release

. ( See also the discussion of “secondary ignition” under the General Instructions .) E xample s of such a n incident would be anInstructions (rev 12

- 2012) for Form PHMSA F 7100.2 (rev 12

- 2012)

INCIDENT REPORT

– NATURAL AND OTHER GAS TRANSMISSION

AND GATHERING PIPELINE SYSTEMS

Page 26 of 30 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

e quipment 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 part y 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 inv olved digging, drilling, boring, grading, cultivation or

similar excavation activities, report under G 3

- Excavation Damage

.

Damage by Boats, Barges, Drilling Rigs, or Other Maritime Equipment or Vessels Set

Adrift or Which Have Otherwise Lost Their Moo ring. 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 inc ludes 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 i ncidents 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 s ection 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.

Rou tine or Normal Fishing or Other Maritime Activity NOT Engaged in Excavation. This

sub

- cause includes incidents due to shrimping, purse se ining, 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 G 3

- Excavation Damage )

.

Electrical Arcing from Othe r 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 apparen tly 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 r elated 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 Exca vation 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 F unctions, 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 In cident

.

Other Outside Force Damage. Select this sub

- cause for types of Other Outside Force Damage not included otherwise, and d e scribe in the space provided . I f necessary, provide additional explanation in P ART H

– Narrative Description of the Incident

.

G 5

– Material Failure of Pipe or Weld

Use this section to report material failures only if “Item Involved in Incident ” ( P ART C, Question 3 ) is “ P ipe ” (whether “ Pipe Body ” or “ Pipe Seam ” ) or “ W eld .” Indicate how the sub

cause was determined or if the sub

- cause is still being investigated.

This section includes releases in or failures from defects or anomalies within the material of the pipe body or within the pipe seam or other weld due to 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

Page 28 of 30 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 pi pe welds , including welding or other activities performed at the facility. Included are release s 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 weld s 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. T his option is not appropriate for wrinkle bends, field welds, girth welds, or other join t s 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.

G 6

– Equipment Failure

This section applies to failures of items other than “ Pipe ” ( “ Pipe Body ” or “ Pipe Seam ” ) or

“ Weld ”

.

E quipment Failure includes a release or failure resulting from : malfunction of control/relief equipment including valves, regulators, or other instrumenta tion; 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

- , installati on

- , 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 s ome 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 f or types of Equipment Failure not included otherwise, and d escribe in the space provided . I f necessary, provide additional explanation in

P ART 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 G 7

– 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 equipme nt.

Other Incorrect Operation

. Select this sub

- cause f or types of Incorrect Operation not included otherwise, and d escribe in the space provided . If n ecessary, provide additional explanation in

P ART H

– Narrative Description of the Incident.

G 8

– Other Incident Cause

This section is provided for incident s 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 in to any of the main cause categor ies

listed in s ections G 1 thr u G 7.

If the incident cause is known but doesn’t fit in to any category in sections G 1 thr u G 7, select

Miscellaneous and enter a description of the incident cause, continuing with a more thorough explanation in P ART H

- Narrative Description of the Incident

.

If the in cident 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 in cident 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 ne w, 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 th is time, and not only that information

rela ted 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 be comes available

. In those cases in which investigations are ongoing for an extended period of time, o perators are to file a S upplemental

R eport 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, f inal determination of the apparent cause and/or closure of the investigation does NOT preclu de 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 pe rtinent. 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 onl y) containing sketches, drawings, or additional

data.

If you selected Miscellaneous in s ection G 8, 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 t o contact the person or persons most knowledgeable). E nter 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 individ ual signing as the Authorized Signature.