# Failure Report- Tennessee Gas Pipeline Company 3/1/11

- **operation:** document
- **citation:** PHMSA FIR, Tennessee Gas Pipeline Company, 2011-03-01
- **title:** Failure Report- Tennessee Gas Pipeline Company 3/1/11
- **source type:** incident
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2017-01-11
- **effective on:** 2011-03-01
- **summary:** Tennessee Gas Pipeline Company; Gas Transmission; OH; failure 2011-03-01; apparent cause: Material Failure.
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- **source url:** https://www.phmsa.dot.gov/safety-reports/failure-report-tennessee-gas-pipeline-company-3111
**body:**

<<<PAGE 1>>>

DOT U.S. Department of Transportation
PHMSA Pipeline and Hazardous Materials Safety Administration
OPS Office of Pipeline Safety
Central Region
Principal Investigator Gery Bauman/Public Utilities Commission of Ohio (PUCO)
Senior Accident Investigator Brian Pierzina/Karen Butler
Region Director David Barrett/Allan Beshore
Date of Report 7/30/2015
Subject Failure Investigation Report—Tennessee Gas Pipeline
Company—Material Failure—Girth Weld
Operator, Location, & Consequences
Date of Failure 3/1/2011
Commodity Released Natural Gas
City/County & State Cumberland/Guernsey, OH
OpID & Operator Name 19160 Tennessee Gas Pipeline Company
Unit # & Unit Name 9413 DIVISION E [IA]
SMART Activity # 133678
Milepost/Location Line 200-1/209-1 + 2258
Type of Failure Rupture, Material Failure, Girth Weld
Fatalities 0
Injuries 0
Description of area impacted Class 1, Rural area, Non-HCA
Total Costs $ 389,949

<<<PAGE 2>>>

Failure Investigation Report—Tennessee Gas Pipeline Company
Material Failure, Girth Weld
Failure Date 3/1/2011
Executive Summary
On March 1, 2011, at approximately 7:15 a.m. EST,
1 Tennessee Gas Pipeline Company (TGP) personnel
detected a natural gas release on the 26-inch diameter 200-1 pipeline downstream of the 209
Compressor Station in Guernsey County, near Cumberland, Ohio. The employees heard a hissing sound
downstream (northeast) of the compressor station when they reported to work in the morning. After
investigating, they confirmed a release coming from the 200-1 pipeline approximately 2,250 feet
downstream of the compressor station. Immediate measures were taken to shut down and isolate the
pipeline, including closing main line block valves (MLBVs) upstream and downstream from the release
location.
The failure occurred in a wooded area near a pasture (Class 1 location, Rural, Non-HCA) approximately
1,200 feet from the nearest residence, and was discovered to be the result of a ruptured girth weld. The
failed weld was removed—along with the adjacent welds upstream and downstream from the failure
location—and sent to an independent metallurgical laboratory for analysis. The metallurgical analysis
determined the failure was the result of a crack around the top portion of the girth weld dating back to
1950, the year of the original construction. The crack was what is referred to as an underbead crack,
cold crack, or hydrogen-assisted crack. It was approximately 31 inches long circumferentially, centered
from the 10:00 o’clock to 2:40 o’clock position on the pipe. Stresses associated with pipe bend, possible
ground movement, and/or operational changes may have contributed to the eventual failure of the
weld. When the first cut was made to remove the failed pipe the pipe ends shifted, indicating the
presence of residual stresses on the pipeline. Additional cracks were identified outside of the failed
portion of the girth weld, and the adjacent girth weld upstream from the failure had a similar crack that
was determined to date to original construction, but was not leaking.
Based upon information provided by the TGP, it appears the failure occurred at 3:42 a.m. at a pressure
of 709 pounds per square inch gage (psig). There were no injuries or evacuations associated with this
incident, and the escaping gas did not ignite. The total reported costs associated with emergency
response, pipe replacement, and site clean-up were $389,949.
System Details
The TGP is an interstate natural gas transmission pipeline operator with approximately 12,000 miles of
pipeline, including 876 miles in Ohio. The TGP system in Ohio consists of four essentially parallel
pipelines that travel across the Ohio River near Portsmouth, Ohio, in a northeasterly direction, ending
near Boardman, Ohio. The four pipelines generally, but not always, share a common right-of-way. The
failure occurred on the Line 200-1 pipeline, a 26-inch diameter, 0.281-inch wall thickness, API 5LX Grade
X-52, electric flash-welded (EFW) pipe manufactured by A.O. Smith. The pipeline was coated with coal
tar enamel and asbestos wrap, and cathodically protected with impressed current. This pipeline was
constructed in 1950 with a maximum allowable operating pressure (MAOP) of 790 psig. The pipeline
section containing the girth weld was hydrostatically pressure tested without failure on September 27,
1969, and was in a no-flow condition at the time the leak was discovered due to ongoing downstream
pipeline repairs being performed on Line Section 214-1. When the pipeline was constructed in 1950,
pipeline girth welds were not typically nondestructively tested. In 2004, the TGP ran a high-resolution
Magnetic Flux Leakage (MFL) and Caliper In-line inspection (ILI). The ILI data was examined for
1 All times are Eastern Standard Time (EST) unless otherwise noted.
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<<<PAGE 3>>>

Failure Investigation Report—Tennessee Gas Pipeline Company
Material Failure, Girth Weld
Failure Date 3/1/2011
indications of dents and metal loss, but was not subjected to an analysis that considered girth weld
defects.
Events Leading up to the Failure
On February 10, 2011, at approximately 10:30 p.m., the TGP experienced a pipeline rupture (girth weld
failure) on the Line 214-4 pipeline near Hanoverton, Ohio. Station 209 was operating when this failure
occurred, but was taken offline as a result of the rupture and subsequent fire approximately 15 minutes
later. As the emergency response to the Hanoverton incident progressed, TGP Incident Command
determined it would be necessary to bring Station 209 back online to maintain service to customers.
The request to bring Station 209 back online (for Lines 1, 2, and 3) was made at at 10:56 p.m. It was
unknown at that time that the auto-close valves for all four pipelines at Valve Station 215 had closed
due to the rupture and fire. When Station 209 was brought back online, the gas discharge pressure rose
rapidly from 740 psig to 765 psig between 12:18 a.m. and 12:23 a.m., then dropping to 743 psig by
12:28 a.m. From that point on discharge pressure rose gradually, reaching a maximum recorded
pressure of 782 psig at 1:24 a.m., when Incident Command requested Station 209 be shut down. When
it was determined that all four auto-close valves at Valve Station 215 had closed, and the TGP system
isolated at that location, alternative means of providing service to distribution customers was
established. This allowed Station 209 to remain offline until after the necessary repairs at 215-1 were
completed; those repairs were still in process when the March 1, 2011, incident occurred. There were
no reported maintenance activities on the section of pipe just downstream of Compressor Station 209 in
the area of the leak prior to March 1, 2011.
Emergency Response
The leak was initially discovered by TGP employees when they reported for work at Compressor Station
209 after they investigated a sound of escaping gas that could be heard from the station. Only two of
the four pipelines in the area of the failure share a common right-of-way, so the employees were quickly
able to determine the release was coming from Line 1. The employees then began the process of
isolating the pipeline, closing MLBV 209-1 (upstream from the failure) at Compressor Station 209 at 8:00
a.m. and MLBV 210-1 (downstream from the failure) at 8:20 a.m. This isolated approximately 12 miles
of Line 1, including the failure location. The pressure on Line 1 was then monitored for a period of time,
with a pressure drop from 658 psig to 464 psig observed from 8:23 a.m. to 9:20 a.m. After receiving this
additional confirmation that Line 1 was leaking, the TGP employees prepared to blowdown the section
of Line 1 between MLBV 209-1 and MLBV 210-1. The blowdown process began at 10:47 a.m. and was
completed by 12:30 p.m. There was no fire or explosion associated with the incident. The TGP notified
the National Response Center (NRC) at 10:12 a.m. (NRC Report #968824), reporting that “a 26-inch steel
pipeline appears to have a leak due to unknown causes.” Both the Public Utilities Commission of Ohio
(PUCO) and the Pipeline and Hazardous Materials Safety Administration (PHMSA) Central Region
Inspectors were dispatched to investigate. The PUCO inspector was in the area inspecting a different
pipeline operator, and arrived on-site at 11:25 a.m. The inspectors were able to provide field
observations, gather background information, and monitor investigation and repair activities.
Excavation of the failure location did not begin until the morning of March 2, 2011.
Summary of Return-to-Service
PHMSA issued a Notice of Proposed Safety Order (NOPSO) to the TGP (CPF No. 3-2011-1001S) on March
11, 2011, addressing both the failure on February 10, 2011, at Line 214-4, and the failure on March 1,
2011, at 209-1. The NOPSO provisions required a written restart plan, 20% pressure reduction, airborne
instrumented leak survey, accelerated patrol surveillance activities, 3rd
-party mechanical and
Page 3 of 6

<<<PAGE 4>>>

Failure Investigation Report—Tennessee Gas Pipeline Company
Material Failure, Girth Weld
Failure Date 3/1/2011
metallurgical testing and failure analysis, historical ILI data re-analysis, performance of additional ILI,
evaluation of the results for girth weld anomalies, analysis of Supervisory Control and Data Acquisition
(SCADA) activities, root cause analysis, development and implementation of an integrity verification and
remedial work plan, and monthly status reports. Good faith settlement discussions between the TGP
and PHMSA culminated in a Consent Agreement that described the work to be performed to remediate
the integrity risks associated with the pipelines.
On March 22, 2011, the TGP replaced 86 feet of the Line 1 pipe with pre-tested pipe. Even though the
pipeline remained out of service, it was purged and loaded with natural gas to facilitate the required
leakage survey from 209-1 to 210-1. Following the leakage survey, this section of Line 1 remained out of
service, isolated at a pressure of 475 psig. During May 2011, with PHMSA’s approval, the TGP
temporarily increased the pressure on Line 1 from 209-1 to 214-1 in order to facilitate the cleaning tool,
gauge tool, and inspection tool runs required by the Consent Agreement. These activities were
completed by May 12, 2011, after which the section between 209-1 and 210-1 was isolated once more
and locked in at a pressure of 522 psig. Following investigation and remediation of anomalies reported
by the prior and most recent ILI reviews, the TGP requested—and was granted—permission to return
the 209 to 210 section of Line 1 to service at full operating pressure. This was completed on October 28,
2011.
Investigation Details
After the area of the rupture was made safe, the rupture site was examined by employees of the TGP,
PHMSA, and the Gas Pipeline Safety Section of PUCO. Records were requested regarding the history
and operation of the pipeline, and the TGP hired Det Norske Veritas (DNV) to complete a metallurgical
investigation of the failure. During the pipe removal process, the upstream and downstream welds
were radiographed and crack-like indications were observed in the upstream weld. As a result, the
failed girth weld and both the upstream and downstream welds were sent to the DNV for metallurgical
investigation.
Pipe sections involving the three girth welds were removed and shipped to the DNV’s Columbus location
for a metallurgical investigation to determine the cause of the failure. The TGP expanded their root
cause analysis (RCA) associated with the February 10, 2011, incident to include this girth weld failure.
The RCA team was comprised of subject matter experts from the TGP and outside contractors.
Additionally, soil scientists from Battelle Memorial Institute conducted a geologic and soil investigation
into the failure.
The results of the metallurgical analysis2 offered the following conclusions and discussion:
The results of the metallurgical analysis indicate that the leak initiated at a pre-existing crack in a
field girth weld. The crack was 2.6 feet long, circumferentially, and was located on the inside of
the pipe between the 10:00 and 2:40 o’clock orientations. The maximum depth of the crack was
0.317 inches (79% through wall based on a pipe wall/girth weld thickness of 0.399 inches). The
pre-existing crack initiated at the toe of the root pass in the heat-affected zone of the weld. The
crack propagated primarily in the weld metal. The crack did alternate between the upstream
and downstream root pass as it propagated. This type of crack is referred to as an under-bead
crack, cold crack, or hydrogen assisted crack. A discussion of the factors related to hydrogen-
assisted cracking is given in Appendix B of the metallurgical report.
2 DNV Final Report—Metallurgical Analysis of Girth Weld Leak on Tennessee Gas Pipeline’s 200-1 Line at Milepost
209-1 + 0.44—May 20, 2011.
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<<<PAGE 5>>>

Failure Investigation Report—Tennessee Gas Pipeline Company
Material Failure, Girth Weld
Failure Date 3/1/2011
The primary cause of the leak was the presence of the pre-existing weld crack. A contributing
factor in the failure was tensile axial stresses acting on the girth weld. The presence of the weld
crack near the top of the pipe suggests that bending stresses acted on the pipe to place the
crack in tension. This is consistent with shifting of the pipe after the initial field cut, in which the
upstream end shifted upwards approximately 2.5 inches. Approximately 91 feet of the pipeline
was excavated (approximately 45.5 feet on both sides of the failed girth weld) at the time of the
initial cut.
Below is a summary of observations from the metallurgical analysis.
 The leak occurred at a field girth weld.
 A pre-existing weld crack was associated with the leak.
 The pre-existing crack was approximately 2.6 feet long, circumferentially, and
located
 between the 10:00 and 2:40 o’clock orientations.
 The maximum depth of the crack was approximately 0.317 inches,
corresponding to 79% through wall based on a pipe wall/girth weld thickness of
0.399 inches. The final brittle fracture was approximately 0.08 inches deep
corresponding to 21% of the pipe wall / girth weld thickness.
 The crack originated at the toe of the weld root pass and extended through the
weld metal of the girth weld.
 Intergranular fractographic features were present in Regions 1 and 2 of the
crack.
Findings and Contributing Factors
1. There was a change in the operational history of the Cumberland Compressor Station
immediately upstream of the failed girth weld. The pipeline was shut-in due to the repair of the
downstream girth weld failure, and the ambient temperature at the time of failure was 24
degrees Fahrenheit. The cooler operating temperature of the pipeline could have increased
tensile stresses due to thermal contraction of the pipe.
2. Typically, pipelines are bent during construction to conform to local topography. The section of
pipe in the immediate vicinity of the girth weld contained a 7.9-degree sag bend; upon
replacement of the pipeline section, however, a sag bend of 5.5 degrees was installed to fit the
topography. The difference of 2.4 degrees between the original and replacement construction
indicates the possibility of bending stresses acting across the weld.
3. A geological analysis of the soil and the topography of the pipeline right-of-way in the vicinity of
the failed weld indicated soil creep perpendicular to the pipeline. This extremely slow ground
movement could increase the tensile stresses across the girth weld over time, leading to its
failure.
4. The results of the DNV metallurgical investigation showed the failed girth weld contained a
preexisting crack that extended through part of the girth weld. The preexisting crack initiated at
the toe of the root bead and penetrated through part of the weld. The crack was 2.6 feet long
circumferentially, and had a maximum depth of 0.317 inches (79% of the way through the wall
based on a total weld thickness of 0.399 inches). The laboratory classified the crack as a
hydrogen crack, also known as an under-bead crack, cold crack, or hydrogen-assisted crack. The
conculsion that it was a hydrogen crack that led to this failure is supported by the metallurgy of
the pipe and the welding electrodes used to complete the weld, as well as experience gained
Page 5 of 6

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Failure Investigation Report—Tennessee Gas Pipeline Company
Material Failure, Girth Weld
Failure Date 3/1/2011
regarding welding since the pipeline was built in 1950. No signs of fatigue were observed; the
crack formed during construction of the pipeline and remained dormant from the date of
construction until the time of failure.
5. The restart of Station 209 during the Line 214-4 incident on February 10-11, 2011, was initiated
shortly after the incident. Fires were still burning at this time, and the status of Lines 1, 2, and 3
was unconfirmed. As a result of all four pipelines being isolated at Valve Station 215, the
discharge pressure at 209-1 reached at least 782 psig prior to the station being shut down again.
The pressure records provided by the TGP for the period following this event show that the
pressure at 209 was maintained between 630 psig and 670 psig until the end of February. The
pressure began to increase steadily on February 28th
, rising from 670 psig to 709 psig, at which
point the failure occurred. It’s possible this pressure cycle, just 18 days before the failure, may
have been sufficient to destabilize the previously dormant defect.
Appendices
A Map and Photographs
B NRC Report
C Operator’s Report
D Metallurgical Analysis
E Root Cause Analysis (RCA)
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Appendix A - Map and Photographs
Materials Safety Administratior
Pipeline and Hazardou
OPID 19160 Tennessee Gas Pipeline Co. - Cumberland, OH Incident
:153
1.5
- Mies
PHMSA CENTRAL REGION
Page 1 of 5

<<<PAGE 8>>>

Appendix A - Map and Photographs
Photo 1 view of leak site looking south down the right-of-way. The compressor station can be seen in
the distance. The disturbed soil was blown from the ground as a result of the failed girth weld.
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Appendix A - Map and Photographs
Photo 2 shows the excavation around the failed girth weld.
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Appendix A - Map and Photographs
Photo 3 shows the failed girth weld.
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Appendix A - Map and Photographs
Photo 4 shows a close-up of the top of the failed girth weld.
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<<<PAGE 12>>>

Appendix B - NRC Report
Page 1 of 2
NATIONAL RESPONSE CENTER 1-800-424-8802
*** For Public Use ***
Information released to a third party shall comply with any
applicable federal and/or state Freedom of Information and Privacy Laws
Incident Report # 968824
INCIDENT DESCRIPTION
*Report taken at 10:12 on 01-MAR-11
Incident Type: PIPELINE
Incident Cause: UNKNOWN
Affected Area:
The incident was discovered on 01-MAR-11 at 09:15 local time.
Affected Medium: AIR INTO THE AIR
SUSPECTED RESPONSIBLE PARTY
Organization: TENNESSEE GAS PIPELINE
HOUSTON, TX 77046
Type of Organization: PRIVATE ENTERPRISE
INCIDENT LOCATION
SEE LAT/LONG County: GUERNSEY
COUNTY RD 15
CLAYSVILLE RD
City: CLAYSVILLE State: OH Zip: 77046
Latitude: 39 57' 12" N
Longitude: 081 40' 33" W
____________________________________________________________________________
RELEASED MATERIAL(S)
CHRIS Code: ONG Official Material Name: NATURAL GAS
Also Known As:
Qty Released: 0 UNKNOWN AMOUNT
DESCRIPTION OF INCIDENT
THE CALLER IS REPORTING THAT A 26 INCH STEEL PIPELINE APPEARS TO HAVE A LEAK DUE TO
UNKNOWN CAUSES. AN UNKNOWN AMOUNT OF NATURAL GAS WAS RELEASED TO THE ATMOSPHERE.
INCIDENT DETAILS
Pipeline Type: TRANSMISSION
DOT Regulated: YES
Pipeline Above/Below Ground: BELOW
Exposed or Under Water: NO
Pipeline Covered: UNKNOWN
DAMAGES
Fire Involved: NO Fire Extinguished: UNKNOWN
INJURIES: NO Hospitalized: Empl/Crew: Passenger:
FATALITIES: NO Empl/Crew: Passenger: Occupant:
EVACUATIONS: NO Who Evacuated: Radius/Area:
Damages: NO
Length of Direction of
Closure Type Description of Closure Closure Closure
Air: N
Road: N
Waterway: N
Track: N
Passengers Transferred: NO
Environmental Impact: UNKNOWN
Media Interest: NONE Community Impact due to Material:
Major
Artery:
N
REMEDIAL ACTIONS
THEY HAVE ISOLATED THE PIPELINE AND WILL DEPRESSURE IT.
Release Secured: NO
http://www.nrc.uscg.mil/reports/rwservlet?standard_web+inc_seq=968824
5/24/2013
Page 1 of 2

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Appendix B - NRC Report
Page 2 of 2
Release Rate:
Estimated Release Duration:
WEATHER
Weather: PARTLY CLOUDY, 32ºF Wind speed: 2 MPH Wind directi
ADDITIONAL AGENCIES NOTIFIED
Federal: NONE
State/Local: OH PUC
State/Local On Scene: NONE
State Agency Number: NONE
NOTIFICATIONS BY NRC
ATLANTIC STRIKE TEAM (MAIN OFFICE)
01-MAR-11 10:19
USCG ICC (ICC ONI)
01-MAR-11 10:19
CGIS RAO ST. LOUIS (COMMAND CENTER)
01-MAR-11 10:19
DOT CRISIS MANAGEMENT CENTER (MAIN OFFICE)
01-MAR-11 10:19
U.S. EPA V (MAIN OFFICE)
01-MAR-11 10:21
NATIONAL INFRASTRUCTURE COORD CTR (MAIN OFFICE)
01-MAR-11 10:19
NOAA RPTS FOR OH (MAIN OFFICE)
01-MAR-11 10:19
OHIO DEPARTMENT OF HEALTH (OHDOH)
01-MAR-11 10:19
SECTOR OHIO VALLEY (COMMAND CENTER)
01-MAR-11 10:19
OH EPA ATTN: DUTY OFFICER (MAIN OFFICE)
01-MAR-11 10:19
OH EPA ATTN: DUTY OFFICER (SOUTHEAST DISTRICT OFFICE)
01-MAR-11 10:19
ADDITIONAL INFORMATION
NO ADDITIONAL INFORMATION.
*** END INCIDENT REPORT # 968824 ***
http://www.nrc.uscg.mil/reports/rwservlet?standard_web+inc_seq=968824
5/24/2013
Page 2 of 2

<<<PAGE 14>>>

Appendix C - Operator's Report
NOTICE: This report is required by 49 CFR Part 191. Failure to report can result in a civil penalty not to
exceed 100,000 for each viola ion for each day that such violation persists except that the maximum civil
penalty shall not exceed $1,000,000 as provided in 49 USC 60122.
OMB NO: 2137-0522
EXPIRATION DATE: 10/31/2016
Original Report
Date: 03/28/2011
U.S Department of Transportation
Pipeline and Hazardous Materials Safety Administration
No. 20110036 - 16819
--------------------------------------------------
(DOT Use Only)
INCIDENT REPORT - GAS TRANSMISSION AND
GATHERING PIPELINE SYSTEMS
A federal agency may not conduct or sponsor, and a person is not required to respond to, nor shall a person be subject to a penalty for failure to comply
with a collection of information subject to the requirements of the Paperwork Reduction Act unless that collection of information displays a current valid
OMB Control Number. The OMB Control Number for this information collection is 2137-0522. All responses to this collection of information are
mandatory. Send comments regarding the burden estimate or any other aspect of his collection of information, including suggestions for reducing the
burden to: Information Collection Clearance Officer, PHMSA, Office of Pipeline Safety (PHP-30) 1200 New Jersey Avenue, SE, Washington, D.C. 20590.
INSTRUCTIONS
Important: Please read the separate instructions for completing this form before you begin. They clarify the information requested and provide specific
examples. If you do not have a copy of the instructions, you can obtain one from the PHMSA Pipeline Safety Community Web Page at
http://www.phmsa.dot.gov/pipeline/library/forms.
PART A - KEY REPORT INFORMATION
Report Type: (select all that apply) Original: Supplemental: Yes Final:
Yes
Last Revision Date: 07/20/2015
1. Operator's OPS-issued Operator Identification Number (OPID): 19160
2. Name of Operator TENNESSEE GAS PIPELINE COMPANY
3. Address of Operator:
3a. Street Address 1001 LOUISIANA ST SUITE 1000
3b. City HOUSTON
3c. State Texas
3d. Zip Code: 77002
4. Local time (24-hr clock) and date of the Incident: 03/01/2011 07:15
5. Location of Incident:
Latitude: 39.945198
Longitude: -81.680369
6. National Response Center Report Number (if applicable): 968824
7. Local time (24-hr clock) and date of initial telephonic report to the
National Response Center (if applicable): 03/01/2011 10:12
8. Incident resulted from: Unintentional release of gas
9. Gas released: (select only one, based on predominant volume
released) Natural Gas
- Other Gas Released Name:
10. Estimated volume of commodity released unintentionally - Thousand
Cubic Feet (MCF): 29,745.00
11. Estimated volume of intentional and controlled release/blowdown -
Thousand Cubic Feet (MCF) 13,338.00
12. Estimated volume of accompanying liquid release (Barrels):
13. Were there fatalities? No
- If Yes, specify the number in each category:
13a. Operator employees
13b. Contractor employees working for the Operator
13c. Non-Operator emergency responders
13d. Workers working on the right-of-way, but NOT
associated with this Operator
13e. General public
13f. Total fatalities (sum of above)
14. Were there injuries requiring inpatient hospitalization? No
- If Yes, specify the number in each category:
14a. Operator employees
14b. Contractor employees working for the Operator
14c. Non-Operator emergency responders
14d. Workers working on the right-of-way, but NOT
associated with this Operator
14e. General public
14f. Total injuries (sum of above)
15. Was the pipeline/facility shut down due to the incident? Yes
- If No, Explain:
Form PHMSA F 7100.2 Page 1 of 13
Reproduction of this form is permitted
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<<<PAGE 15>>>

Appendix C - Operator's Report
- If Yes, complete Questions 15a and 15b: (use local time, 24-hr clock)
15a. Local time and date of shutdown 03/01/2011 08:20
15b. Local time pipeline/facility restarted 03/22/2011 16:09
- Still shut down? (* Supplemental Report Required)
16. Did the gas ignite? No
17. Did the gas explode? No
18. Number of general public evacuated: 0
19. Time sequence (use local time, 24-hour clock):
19a. Local time operator identified Incident– effective 10-2014,
changed from "Incident" to "failure" 03/01/2011 07:15
19b. Local time operator resources arrived on site 03/01/2011 08:00
PART B - ADDITIONAL LOCATION INFORMATION
1. Was the origin of the Incident onshore? Yes
- Yes (Complete Questions 2-12)
- No (Complete Questions 13-15)
If Onshore:
2. State: Ohio
3. Zip Code: 43732
4. City Cumberland
5. County or Parish Guernsey
6. Operator designated location Milepost/Valve Station
Specify: 209-1@2258
7. Pipeline/Facility name: Line 200-1
8. Segment name/ID: Valve Section 209-1
9. Was Incident on Federal land, other than the Outer Continental Shelf
(OCS)? No
10. Location of Incident : Pipeline Right-of-way
11. Area of Incident (as found) : Underground
Specify: Under soil
Other – Descr be:
Depth-of-Cover (in): 33
12. Did Incident occur in a crossing? No
- If Yes, specify type below:
- If Bridge crossing –
Cased/ Uncased:
- If Railroad crossing –
Cased/ Uncased/ Bored/drilled
- If Road crossing –
Cased/ Uncased/ Bored/drilled
- If Water crossing –
Cased/ Uncased
Name of body of water (If commonly known):
Approx. water depth (ft) at the point of the Incident:
Select:
If Offshore:
13. Approx. water depth (ft) at the point of the Incident:
14. Origin of Incident:
- If "In State waters":
- State:
- Area:
- Block/Tract #:
- Nearest County/Parish:
- If "On the Outer Continental Shelf (OCS)":
- Area:
- Block #:
15. Area of Incident:
PART C - ADDITIONAL FACILITY INFORMATION
1. Is the pipeline or facility: - Interstate - Intrastate Interstate
2. Part of system involved in Incident: Onshore Pipeline, Including Valve Sites
3. Item involved in Incident: Weld, including heat-affected zone
- If Pipe – Specify:
3a. Nominal diameter of pipe (in): 26
3b. Wall thickness (in): .281
3c. SMYS (Specified Minimum Yield Strength) of pipe (psi): 52,000
Form PHMSA F 7100.2 Page 2 of 13
Reproduction of this form is permitted
Page 2 of 13

<<<PAGE 16>>>

Appendix C - Operator's Report
3d. Pipe specification: Exceeds API 5L
3e. Pipe Seam – Specify: Flash Welded
- If Other, Describe:
3f. Pipe manufacturer: A.O. Smith
3g. Year of manufacture: 1950
3h. Pipeline coating type at point of Incident – Specify: Coal Tar
- If Other, Describe:
- If Weld, including heat-affected zone – Specify: Pipe Girth Weld
- If Other, Describe:
- If Valve – Specify:
- If Mainline – Specify:
- If Other, Describe:
3i. Mainline valve manufacturer:
3j. Year of manufacture:
- If Other, Descr be:
4. Year item involved in Incident was installed: 1950
5. Material involved in Incident: Carbon Steel
- If Material other than Carbon Steel or Plastic – Specify:
6. Type of Incident involved: Rupture
- If Mechanical Puncture – Specify Approx. size:
in. (axial) by
in. (circumferential)
- If Leak - Select Type:
- If Other – Describe:
- If Rupture - Select Orientation: Circumferential
- If Other – Descr be:
Approx. size: in. (widest opening): .4
by in. (length circumferentially or axially): 31.2
- If Other – Describe:
PART D - ADDITIONAL CONSEQUENCE INFORMATION
1. Class Location of Incident: Class 1 Location
2. Did this Incident occur in a High Consequence Area (HCA)? No
- If Yes:
2a. Specify the Method used to identify the HCA:
3. What is the PIR (Potential Impact Radius) for the location of this
Incident? Feet: 504
4. Were any structures outside the PIR impacted or otherwise damaged
due to heat/fire resulting from the Incident? No
5. Were any structures outside the PIR impacted or otherwise damaged
NOT by heat/fire resulting from the Incident? No
6. Were any of the fatalities or injuries reported for persons located
outside the PIR? No
7. Estimated Property Damage :
7a. Estimated cost of public and non-Operator private
property damage paid/reimbursed by the Operator – effective 6-
2011, "paid/reimbursed by the Operator" removed
$ 10,000
Estimated cost of gas released unintentionally – effective 6-2011,
moved to item 7f
Estimated cost of gas released during intentional and controlled
blowdown – effective 6-2011, moved to item 7g
7b. Estimated cost of Operator's property damage & repairs $ 200,825
7c. Estimated cost of Operator's emergency response $ 6,800
7d. Estimated other costs $ 0
Describe:
7e. Property damage subtotal (sum of above) $ 217,625
Cost of Gas Released
7f. Estimated cost of gas released unintentionally $ 118,980
7g. Estimated cost of gas released during intentional and
controlled blowdown $ 53,344
7h. Total estimated cost of gas released (sum of 7.f & 7.g above) $ 172,324
Total of all costs $ 389,949
Form PHMSA F 7100.2 Page 3 of 13
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Appendix C - Operator's Report
PART E - ADDITIONAL OPERATING INFORMATION
1. Estimated pressure at the point and time of the Incident (psig): 709.00
2. Maximum Allowable Operating Pressure (MAOP) at the point and
time of the Incident (psig): 790.00
Added 10-2014 2a. MAOP established by 49 CFR section: 192.619(a)(3)
- If Other, specify:
3. Descr be the pressure on the system or facility relating to the
Incident: Pressure did not exceed MAOP
4. Not including pressure reductions required by PHMSA regulations
(such as for repairs and pipe movement), was the system or facility
relating to the Incident operating under an established pressure
restriction with pressure limits below those normally allowed by the
MAOP?
No
- If Yes - (Complete 4a and 4b below)
4a. Did the pressure exceed this established pressure
restriction?
4b. Was this pressure restriction mandated by PHMSA or the
State?
5. Was "Onshore Pipeline, Including Valve Sites" OR "Offshore Pipeline,
Including Riser and Riser Bend" selected in PART C, Question 2? Yes
- If Yes - (Complete 5a. – 5e. below):
5a. Type of upstream valve used to initially isolate release source: Manual
5b. Type of downstream valve used to initially isolate release
source:
Manual
5c. Length of segment isolated between valves (ft): 63,307
5d. Is the pipeline configured to accommodate internal inspection
tools? Yes
- If No – Which physical features limit tool accommodation? (select all that apply)
- Changes in line pipe diameter
- Presence of unsuitable mainline valves
- Tight or mitered pipe bends
- Other passage restrictions (i.e. unbarred tee's, projecting
instrumentation, etc.)
- Extra thick pipe wall (applicable only for magnetic flux
leakage internal inspection tools)
- Other
- If Other, Describe:
5e. For this pipeline, are there operational factors which
significantly complicate the execution of an internal inspection tool
run?
No
- If Yes, which operational factors complicate execution? (select all that apply)
- Excessive debris or scale, wax, or other wall build-up
- Low operating pressure(s)
- Low flow or absence of flow
- Incompatible commodity
- Other
- If Other, Describe:
5f. Function of pipeline system: Transmission System
6. Was a Supervisory Control and Data Acquisition (SCADA)-based
system in place on the pipeline or facility involved in the Incident? Yes
- If Yes:
6a. Was it operating at the time of the Incident? Yes
6b. Was it fully functional at the time of the Incident? Yes
6c. Did SCADA-based information (such as alarm(s), alert(s),
event(s), and/or volume or pack calculations) assist with the
detection of the Incident?
No
6d. Did SCADA-based information (such as alarm(s), alert(s),
event(s), and/or volume calculations) assist with the confirmation of
the Incident?
No
7. How was the Incident initially identified for the Operator? Local Operating Personnel, including contractors
- If Other – Describe:
7a. If "Controller", "Local Operating Personnel, including
contractors", "Air Patrol", or "Ground Patrol by Operator or its
contractor" is selected in Question 7, specify:
Operator employee
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?
No, the Operator did not find that an investigation of the
controller(s) actions or control room issues was necessary
due to: (provide an explanation for why the Operator did not
investigate)
Form PHMSA F 7100.2 Page 4 of 13
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Appendix C - Operator's Report
- If No, the operator did not find that an investigation of the
controller(s) actions or control room issues was necessary due to:
(provide an explanation for why the operator did not investigate)
Pressures were never abnormal or in excess of MAOP.
- If Yes, Describe investigation result(s) (select all that apply):
- Investigation reviewed work schedule rotations, continuous
hours of service (while working for the operator), and other
factors associated with fatigue
- Investigation did NOT review work schedule rotations,
continuous hours of service (while working for the Operator)
and other factors associated with fatigue
- Provide an explanation for why not:
- Investigation identified no control room issues
- Investigation identified no controller issues
- Investigation identified incorrect controller action or
controller error
- Investigation identified that fatigue may have affected the
controller(s) involved or impacted the involved controller(s)
response
- Investigation identified incorrect procedures
- Investigation identified incorrect control room equipment
operation
- Investigation identified maintenance activities that affected
control room operations, procedures, and/or controller
response
- Investigation identified areas other than those above –
Describe:
PART F - DRUG & ALCOHOL TESTING INFORMATION
1. As a result of this Incident, were any Operator employees tested
under the post-accident drug and alcohol testing requirements of DOT's
Drug & Alcohol Testing regulations?
No
- If Yes:
1a. How many were tested:
1b. How many failed:
2. As a result of this Incident, were any Operator contractor employees
tested under the post-accident drug and alcohol testing requirements of
DOT's Drug & Alcohol Testing regulations?
No
- If Yes:
2a. How many were tested:
2b. How many failed:
PART G - APPARENT CAUSE
Select only one box from PART G in the shaded column on the left representing the APPARENT Cause of the Incident, and answer the
questions on the right. Describe secondary, contributing, or root causes of the Incident in the narrative (PART H).
Apparent Cause: G5 - Material Failure of Pipe or Weld
G1 - Corrosion Failure - only one sub-cause can be picked from shaded left-hand column
Corrosion Failure – Sub-cause:
- If External Corrosion:
1. Results of visual examination:
- If Other, Describe:
2. Type of corrosion: (select all that apply)
- Galvanic
- Atmospheric
- Stray Current
- Microbiological
- Selective Seam
- Other
- If Other – Describe:
3. The type(s) of corrosion selected in Question 2 is based on the following: (select all that apply)
- Field examination
- Determined by metallurgical analysis
- Other
- If Other – Describe:
4. Was the failed item buried under the ground?
Form PHMSA F 7100.2 Page 5 of 13
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Appendix C - Operator's Report
- If Yes:
4a. Was failed item considered to be under cathodic protection at
the time of the incident?
- If Yes, Year protection started:
4b. Was shielding, tenting, or disbonding of coating evident at the
point of the incident?
4c. Has one or more Cathodic Protection Survey been conducted
at the point of the incident?
If "Yes, CP Annual Survey" – Most recent year conducted:
If "Yes, Close Interval Survey" – Most recent year conducted:
If "Yes, Other CP Survey" – Most recent year conducted:
- If No:
4d. Was the failed item externally coated or painted?
5. Was there observable damage to the coating or paint in the vicinity of
the corrosion?
- If Internal Corrosion:
6. Results of visual examination:
- If Other, Describe:
7. Cause of corrosion (select all that apply):
- Corrosive Commodity
- Water drop-out/Acid
- Microbiological
- Erosion
- Other
- If Other, Describe:
8. The cause(s) of corrosion selected in Question 7 is based on the following (select all that apply):
- Field examination
- Determined by metallurgical analysis
- Other
- If Other, Describe:
9. Location of corrosion (select all that apply):
- Low point in pipe
- Elbow
- Drop-out
- Other
- If Other, Describe:
10. Was the gas/fluid treated with corrosion inhibitors or biocides?
11. Was the interior coated or lined with protective coating?
12. Were cleaning/dewatering pigs (or other operations) routinely
utilized?
13. Were corrosion coupons routinely utilized?
Complete the following if any Corrosion Failure sub-cause is selected AND the "Item Involved in Incident" (from PART C,
Question 3) is Pipe or Weld.
14. Has one or more internal inspection tool collected data at the point
of the Incident?
14a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run:
- Magnetic Flux Leakage Tool
Most recent year run:
- Ultrasonic
Most recent year run:
- Geometry
Most recent year run:
- Caliper
Most recent year run:
- Crack
Most recent year run:
- Hard Spot
Most recent year run:
- Combination Tool
Most recent year run:
- Transverse Field/Triaxial
Most recent year run:
- Other
Most recent year run:
If Other, Describe:
15. Has one or more hydrotest or other pressure test been conducted
since original construction at the point of the Incident?
- If Yes,
Form PHMSA F 7100.2 Page 6 of 13
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Appendix C - Operator's Report
Most recent year tested:
Test pressure (psig):
16. Has one or more Direct Assessment been conducted on this
segment?
- If Yes, and an investigative dig was conducted at the point of the Incident:
Most recent year conducted:
- If Yes, but the point of the Incident was not identified as a dig site:
Most recent year conducted:
17. Has one or more non-destructive examination been conducted at
the point of the Incident since January 1, 2002?
17a. If Yes, for each examination conducted since January 1, 2002, select type of non-destructive examination and indicate most
recent year the examination was conducted:
- Radiography
Most recent year examined:
- Guided Wave Ultrasonic
Most recent year examined:
- Handheld Ultrasonic Tool
Most recent year examined:
- Wet Magnetic Particle Test
Most recent year examined:
- Dry M
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