# SOUTHERN NATURAL GAS CO — Corrective Action Order

- **operation:** document
- **citation:** CPF 22026009CAO
- **title:** SOUTHERN NATURAL GAS CO — Corrective Action Order
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** current
- **official:** true
- **published on:** 2026-06-01
- **effective on:** Not available
- **summary:** OPEN corrective action order.
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- **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/22026009CAO
**body:**

Corrective Action Order involving SOUTHERN NATURAL GAS CO. The dataset does not identify a cited regulation for this case. The case was opened on 2026-06-01 and is reported as open. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

22026009CAO_Corrective Action Order_06012026_(26-373830).pdf: https://primis.phmsa.dot.gov/enforcement-documents/22026009CAO/22026009CAO_Corrective%20Action%20Order_06012026_(26-373830).pdf

22026009CAO_Corrective Action Order_06012026_(26-373830)_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/22026009CAO/22026009CAO_Corrective%20Action%20Order_06012026_(26-373830)_text.pdf

22026009CAO_Corrective Action Order_06012026_(26-373830)_text.pdf

U.S. Department
of Transportation
Pipeline and
Hazardous Materials
Safety Administration
1200 New Jersey Avenue, S.E.
Washington, D.C. 20590
June 1, 2026
VIA ELECTRONIC MAIL TO: steven_romano@kindermorgan.com
Steven Romano
Chief Operating Officer
Southern Natural Gas Company
1001 Louisiana Street
Suite 1000
Houston, TX 77002
CPF 2-2026-009-CAO
Dear Mr. Romano:
Enclosed please find a Corrective Action Order (“CAO” or “Order”) issued by the Pipeline and
Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS). The CAO
requires Southern Natural Gas Company (SNG) to take certain corrective actions with respect to
the pipeline failure that occurred on May 30, 2026, on the South Main System in Clarke County,
Mississippi.
Service of the CAO by email is effective upon the date of transmission and acknowledgment of
receipt as provided under 49 CFR § 190.5. The terms and conditions of this Order are effective
upon completion of service.
Sincerely,
Keith Coyle
Chief Counsel
Pipeline and Hazardous Materials Safety
Administration
Enclosure: CAO
cc: James Urisko, Director, Southern Region, Office of Pipeline Safety, PHMSA
Zachary Ragain – Director – Codes and Standards, Kinder-Morgan
Zach_Ragain@kindermorgan.com
Claudia Pankowski, Manager of Engineering, Codes and Standards, Kinder Morgan,
claudia_pankowski@kindermorgan.com
CONFIRMATION OF RECEIPT REQUESTED



DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, D.C. 20590
____________________________________
In the Matter of )
Southern Natural Gas Company, ) CPF No. 2-2026-009-CAO
)
)
)
Respondent )
____________________________________)
CORRECTIVE ACTION ORDER
Background and Purpose
The Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline
Safety (OPS), is issuing this Corrective Action Order (CAO or Order) pursuant to the authority
provided in 49 U.S.C. § 60112. The CAO requires Southern Natural Gas Company (SNG or
Respondent), a subsidiary of Kinder Morgan, to take certain necessary corrective actions to
protect the public, property, and the environment from the potential hazards associated with the
continued operation of the South Main Line. The South Main Line is part of the South Main
System, which transports natural gas from central Mississippi to central Georgia, serving
numerous customers throughout the region.
On May 30, 2026, the South Main Line pipeline ruptured in a rural area in Clarke County,
Mississippi, resulting in the release of natural gas and evacuation of five nearby homes (Failure
or Incident). The Failure caused a portion of the pipeline to self-excavate from the ground and
exposed an adjoining pipeline located in the same right-of-way. The cause of the Failure remains
under investigation. Another portion of the same pipeline failed in 2022. PHMSA issued a CAO
following the 2022 failure.1
Pursuant to 49 U.S.C. § 60117, PHMSA has initiated an investigation of the Failure. The
preliminary findings of PHMSA’s ongoing investigation are as follows:
● The 221 miles of SNG’s South Main System that contains the failed 18-inch South Main
Line, an 18-inch diameter, 1951 vintage A.O. Smith X52 pipe, traverses from Gwinville
Compressor Station in Gwinville, Mississippi (MP 0) to Elmore Compressor Station in
Elmore, Alabama (MP 221.6). The South Main Line traverses the following counties in
1 See Corrective Action Order, Southern Natural Gas Company, CPF 2-2022-007-CAO (February 18, 2022).



● Mississippi: Jefferson Davis, Simpson, Smith, Jasper, Clarke, and Lauderdale; and the
following counties in Alabama: Sumter, Marengo, Hale, Perry, Dallas, Autauga, and
Elmore.
● On May 30, 2026, at approximately 06:34 AM CDT, the 18-inch South Main Line in the
South Main System ruptured in Clarke County, Mississippi, resulting in the release of
natural gas. The town nearest to the location of the Incident is Enterprise, Mississippi.
● The force of the rupture caused a portion of the 18-inch South Main Line to self-excavate
from the ground, resulting in a 35-foot by 35-foot hole approximately 20-feet deep. The
closest other pipeline, a 24-inch natural gas pipeline part of the South Main loop system,
was exposed from the escaping natural gas. The 24-inch pipeline will remain at 50-psi
until the failed 18-inch South Main Line is repaired; the other 26-inch and 36-inch
pipelines are continuing to operate at normal pressures.
● Prior to the failure, the 18-inch South Main Line operated at pressure of 1155 pounds per
square inch gauge (psig).
● The maximum allowable operating pressure (MAOP) of the 18-inch South Main Line is
1200 psig.
● Approximately seven miles of the failed South Main Line is currently shut-in.
● The South Main Line was manufactured in 1951. It is an A.O. Smith pipe with flash weld
longitudinal seam, 0.312 wall thickness, API 5L grade X52 (52,000 pounds per square
inch specified minimum yield strength), with coal tar enamel coating.
● Cathodic protection (CP) readings taken on site May 31, 2026, indicate that instant off
CP levels were between -0.950mV and -1.1mV, meeting the adopted -0.850mV criteria.
● In February 2022, in Perry County, Alabama, the 18-inch South Main Line experienced a
hard spot failure. That failure was the subject of Corrective Action Order No. 2-2022-
007-CAO.
● PHMSA deployed and arrived onsite on May 31, 2026. An investigation is ongoing.
Determination of Necessity for Corrective Action Order and Right to Hearing
Section 60112 of title 49, United States Code, authorizes PHMSA to determine that a pipeline
facility is or would be hazardous to life, property, or the environment and if there is a likelihood
of serious harm, to expeditiously order the operator of the facility to take necessary corrective
action, including suspended or restricted use of the facility, physical inspection, testing, repair,
replacement, or other appropriate action. An order issued expeditiously must provide an
opportunity for a hearing as soon as practicable after the order is issued.
In deciding whether to issue an order, PHMSA must consider the following, if relevant: (1) the
characteristics of the pipe and other equipment used in the pipeline facility, including the age,
manufacture, physical properties, and method of manufacturing, constructing, or assembling the
equipment; (2) the nature of the material the pipeline facility transports, the corrosive and



deteriorative qualities of the material, the sequence in which the material is transported, and the
pressure required for transporting the material; (3) the aspects of the area in which the pipeline
facility is located, including climatic and geologic conditions and soil characteristics; (4) the
proximity of the area in which the facility is located to environmentally sensitive areas; (5) the
population density and population and growth patterns of the area in which the pipeline facility is
located; (6) any recommendation of the National Transportation Safety Board made under another
law; and (7) any other factors PHMSA may consider as appropriate.
The preliminary findings of fact indicate that the South Main Line was manufactured in 1951, is
an A.O. Smith pipe with flash weld longitudinal seam, 0.312 wall thickness, API 5L grade X52
(52,000 pounds per square inch specified minimum yield strength), and coal tar enamel coating.
The rupture self-excavated the pipeline, constituting damage to the environment, and resulted in
the release of natural gas. The rupture further impacted the nearby 24-inch natural gas pipeline that
is a part of the South Main loop system. The cause of the Failure is currently unknown, and there
is a history of failure on the pipeline. Considering the nature of the Failure, the unknown cause or
causes of the Failure, the age of the pipe and method of manufacture, the operating pressure, the
possibility that the cause or causes associated with the Failure may be present elsewhere on the
South Main Line, the areas in which the pipeline facility is located, the nature of the hazardous
material transported (natural gas), and the existing and potential impacts to life, property, and the
environment, it is hereby determined that continued operation of the Affected Segment, as defined
below, without corrective measures is or would be hazardous to life, property, or the environment,
and that failure to issue this Order expeditiously would result in the likelihood of serious harm.
Accordingly, this Order mandating immediate corrective action is issued expeditiously without
prior notice and opportunity for a hearing. The terms and conditions of this Order are effective
upon completion of service.
Within 10 days of receipt of this Order, Respondent may request a hearing, to be held as soon as
practicable, by notifying the Associate Administrator for Pipeline Safety in writing, with a copy
to the Director, PHMSA, OPS Southern Region. If a hearing is requested, it will be held in
accordance with 49 CFR § 190.211.
After receiving and analyzing additional data in the course of this investigation, PHMSA may
identify other corrective measures that need to be taken. Respondent will be notified of any
additional measures required and, if appropriate, PHMSA will consider a further amended order.
To the extent consistent with safety, Respondent will be afforded notice and an opportunity for a
hearing prior to the imposition of any additional corrective measures.
Corrective Measures
Definitions
Affected Segment – The “Affected Segment” means approximately 221 miles of SNG’s South
Main Line that contains the 18-inch diameter, 1951 vintage A.O. Smith X52 pipe from Gwinville
Compressor Station in Gwinville, Mississippi (MP 0) to Elmore Compressor Station in Elmore,
Alabama (MP 221.6).



Isolated Segment – The “Isolated Segment” means the approximately 8.5-mile segment of
SNG’s South Main Line that contains the 18-inch 1951 vintage A.O. Smith X52 pipe from
Mainline Valve 117 at Mile Post 67.4 to Gate Valve 9 at Mile Post 76.073 at the take off for the
8-inch South Meridian Line.
Failure – The “Failure” means the rupture of the 18-inch South Main Line that occurred at
approximately 6:34 AM CDT on May 30, 2026, in Clarke County, Mississippi.
Director – The “Director” means the Director, PHMSA, OPS Southern Region.
1. Shut Down. SNG must not operate the Isolated Segment until authorized to do so by the
Director.
2. Operating Pressure Restriction. SNG must reduce and maintain a twenty percent (20%)
pressure reduction in the actual operating pressure along the entire length of the Affected
Segment such that the operating pressure along the Affected Segment will not exceed
eighty percent (80%) of the actual operating pressure in effect immediately prior to the
Failure.
a. This pressure restriction is to remain in effect until written approval to increase the
pressure or return the pipeline to its pre-failure operating pressure is obtained from
the Director.
b. Within 15 days of receipt of this Order, SNG must provide the Director the actual
operating pressures of each pump/compressor station and each main line pressure
regulating station on the Affected Segment at the time of failure and the reduced
pressure restriction set-points at these same locations.
c. This pressure restriction requires any relevant remote or local alarm limits, software
programming set-points or control points, and mechanical over-pressure devices to
be adjusted accordingly.
d. When determining the pressure restriction set-points, SNG must take into account
any in-line inspection (ILI) features or anomalies present in the Affected Segment
to provide for continued safe operation while further corrective actions are
completed.
e. SNG must review the pressure restriction monthly by analyzing the operating
pressure data. SNG must take into account any in-line inspection (ILI) features or
anomalies present in the Affected Segment and immediately reduce the operating
pressure to maintain the safe operations of the Affected Segment, if warranted by
the monthly review. SNG must submit the results of the monthly review to the
Director. The results must include, at a minimum, the current discharge set-points
(including any additional pressure reductions), and any pressure exceedance at
discharge set-points.
3. Restart Plan. Prior to resuming operation of the Isolated Segment, SNG must develop and
submit a written Restart Plan to the Director for prior approval.



a. The Director may approve the Restart Plan incrementally without approving the
entire plan but the Isolated Segment cannot resume operation until the Restart Plan
is approved in its entirety.
b. Once approved by the Director, the Restart Plan will be incorporated by reference
into this Order.
c. The Restart Plan must provide for adequate patrolling of the Isolated Segment
during the restart process and must include incremental pressure increases during
start up, with each increment to be held for at least 2 hours.
d. The Restart Plan must specify a day-light restart and include advance
communications with local emergency response officials.
e. The Restart Plan must provide for a review of the Isolated Segment for conditions
similar to those of the Failure including a review of construction, operating and
maintenance (O&M), and integrity management records such as in-line inspection
(ILI) results, hydrostatic tests, root cause failure analysis of prior failures, aerial
and ground patrols, corrosion, cathodic protection, excavations, and pipe
replacements. SNG must address any findings that require remedial measures to be
implemented prior to restart.
f. The Restart Plan must also include documentation of the completion of all
mandated actions, and a management of change plan to ensure that all procedural
modifications are incorporated into SNG’s operations and maintenance procedures
manual.
4. Return to Service. After the Director approves the Restart Plan, SNG may return the
Isolated Segment to service but the operating pressure must not exceed eighty percent
(80%) of the actual operating pressure in effect immediately prior to the Failure on May
30, 2026 in accordance with Item 2 above.
5. Removal of Pressure Restriction. The Director may allow the removal or modification
of the pressure restriction upon a written request from SNG demonstrating that restoring
the pipeline to its pre-failure operating pressure is justified based on a reliable engineering
analysis showing that the pressure increase is safe considering all known defects,
anomalies, and operating parameters of the pipeline.
6. Temporary Modification of Pressure Restrictions. The Director may allow the
temporary removal or modification of the pressure restrictions upon a written request from
SNG demonstrating that temporary mitigative and preventive measures are implemented
prior to and during the temporary removal or modification of the pressure restriction. The
Director's determination will be based on the Failure cause and provision of evidence that
preventative and mitigative actions taken by the operator provide for the safe operation of
the Affected Segment during the temporary removal or modification of the pressure
restriction. Appeals to determinations of the Director in this regard will be decided by the
Associate Administrator for Pipeline Safety.
7. Mechanical and Metallurgical Testing. Within 45 days of receipt of this Order, SNG
must complete mechanical and metallurgical testing and failure analysis of the failed pipe,
including an analysis of soil samples and any foreign materials, and submit the results to
the Director for review. SNG must submit the completed final report of this testing and



analysis to the Director for review and approval. SNG must ensure that all reports, whether
draft or final, are made available in their entirety to the Director at the same time they are
made available to SNG. Mechanical and metallurgical testing must be conducted by an
independent third-party approved by the Director prior to commencing testing and must
document the decision-making process and all factors contributing to the failure.
Respondent must complete the testing and analysis as follows:
a. Document the chain-of-custody when handling and transporting the failed pipe
section and other evidence from the Failure site.
b. Within 10 days of receipt of this Order, develop and submit the testing protocol and
the proposed testing laboratory to the Director for prior approval.
c. Prior to beginning the mechanical and metallurgical testing, provide the Director
with the scheduled date, time, and location of the testing to allow for an OPS
representative to witness the testing.
d. Ensure the testing laboratory distributes all reports whether draft or final in their
entirety to the Director at the same time they are made available to SNG.
8. Root Cause Failure Analysis. Within 90 days following receipt of this Order, SNG must
complete a root cause failure analysis (RCFA) and submit a final report of this RCFA to
the Director for review and approval. No later than 30 days following receipt of this Order,
SNG must provide the scope and protocol of the RCFA to the Director for review and
approval. The RCFA must be conducted by an independent third-party approved by the
Director prior to commencing the analysis and must document the decision-making process
and all factors contributing to the failure. SNG must direct the third-party to engage in
once-a-week calls with PHMSA to provide updates as to the progress of the RCFA. These
calls shall be done virtually and continue until the RCFA has been submitted to the
Director. SNG must ensure that all reports, whether draft or final, are made available in
their entirety to the Director at the same time they are made available to SNG. The final
report must include findings, and any lessons learned and whether the findings and any
lessons learned are applicable to other locations within SNG’s pipeline system.
9. Remedial Work Plan (RWP).
a. Within 60 days of approval of the RCFA required above, SNG must submit a
Remedial Work Plan (RWP) to the Director for approval.
b. The Director may approve the RWP incrementally without approving the entire
RWP.
c. Once approved by the Director, the RWP will be incorporated by reference into this
Order.
d. The RWP must specify the tests, inspections, assessments, evaluations, and
remedial measures SNG will use to verify the integrity of the Affected Segment. It
must address all known or suspected factors and causes of the Failure. SNG should
consider both the risk of another failure and the consequence of another failure to
develop a prioritized schedule for RWP related work along the Affected Segment.
e. The RWP must include a procedure or process to:



i. Identify pipe in the Affected Segment with characteristics similar to the
contributing factors identified for the Failure.
ii. Gather all data necessary to review the failure history (in service and
pressure test failures) of the Affected Segment and to prepare a written
report containing all the available information such as the locations, dates,
and causes of leaks and failures.
iii. Integrate the results of the metallurgical testing, root cause failure analysis,
and other corrective actions required by this Order with all relevant pre-
existing operational and assessment data for the Affected Segment. Pre-
existing operational data includes, but is not limited to, construction,
operations, maintenance, testing, repairs, prior metallurgical analyses, and
any third-party consultation information. Pre-existing assessment data
includes, but is not limited to, ILI tool runs, hydrostatic pressure testing,
direct assessments, close interval surveys, and DCVG/ACVG surveys.
iv. Determine if conditions similar to those contributing to the Failure are likely
to exist elsewhere on the Affected Segment. Conduct additional field tests,
inspections, assessments, and/or evaluations to determine whether, and to
what extent, the conditions associated with the Failure and other failures
from the failure history (see (e)(ii) above) or any other integrity threats are
present elsewhere on the Affected Segment. At a minimum, this process
must consider all failure causes and specify the use of one or more of the
following:
1) Inline inspection (ILI) tools that are technically appropriate for
assessing the pipeline system based on the cause of the Failure and
that can reliably detect and identify anomalies,
2) Hydrostatic pressure testing,
3) Corrosion control methods including cathodic protection and
coating evaluations, close-interval surveys, evaluation of stray
current, and stress corrosion cracking and selective seam corrosion
surveys, if applicable,
4) Other tests, inspections, assessments, and evaluations appropriate
for the Failure causes.
Note: SNG may use the results of previous tests, inspections,
assessments, and evaluations if approved by the Director, provided the
results of the tests, inspections, assessments, and evaluations are
analyzed with regard to the factors known or suspected to have caused
the Failure.
v. Describe the inspection and repair criteria SNG will use to prioritize,
excavate, evaluate, and repair anomalies, imperfections, and other identified
integrity threats, including those related to processes applied per (e)(iv)
above. Include a description of how any defects will be graded and a
schedule for repairs or replacement.



vi. Based on the known history and condition of the Affected Segment,
describe the methods SNG will use to repair, replace, or take other
corrective measures to remediate the conditions associated with the Failure
and to address other known integrity threats along the Affected Segment.
The repair, replacement, or other corrective measures must meet the criteria
specified in (e)(v) above.
vii. Incorporate findings and lessons learned in response to the Failure in all
related programs and procedures to ensure the ongoing safe operation of the
Affected Segment considering the results of the analyses, inspections, and
evaluations resulting from actions taken in response to this Order.
f. Include a proposed schedule for completion of the RWP.
g. SNG must revise the RWP as necessary to incorporate new information obtained
during the failure investigation and remedial activities, to incorporate the results of
actions undertaken pursuant to this Order, and to incorporate modifications
required by the Director. SNG must submit any plan revisions to the Director for
prior approval. The Director may approve plan revisions incrementally. Any and
all revisions to the RWP after it has been approved and incorporated by reference
into this Order will be fully described and documented in the CAO Documentation
Report (CDR).
h. SNG must implement the RWP as it is approved by the Director, including any
revisions to the plan.
10. CAO Documentation Report (CDR). SNG must create and revise, as necessary, a CAO
Documentation Report (CDR). When SNG has concluded all the items in this Order it will
submit the final CDR in its entirety to the Director. This will allow the Director to complete
a thorough review of all actions taken by SNG with regards to this Order prior to approving
the closure of this Order. The intent is for the CDR to summarize all activities and
documentation associated with this Order in one document.
a. The Director may approve the CDR incrementally without approving the entire
CDR.
b. Once approved by the Director, the CDR will be incorporated by reference into this
Order.
c. The CDR must include but not be limited to:
i. Table of Contents;
ii. Summary of the pipeline Failure, and the response activities;
iii. Summary of pipe data and properties and all prior assessments of the
Affected Segment;
iv. Summary of all tests, inspections, assessments, evaluations, and analysis
required by the Order;
v. Summary of the Mechanical and Metallurgical Testing as required by the
Order;



vi. Summary of the RCFA with all root causes as required by the Order;
vii. Documentation of all actions taken by SNG to implement the RWP, the
results of those actions, and the inspection and repair criteria used;
viii. Documentation of any revisions to the RWP including those necessary to
incorporate the results of actions undertaken pursuant to this Order and
whenever necessary to incorporate new information obtained during the
failure investigation and remedial activities;
ix. Lessons learned while completing this Order;
x. A path forward describing specific actions SNG will take on its entire
pipeline system as a result of the lessons learned from work on this Order;
and
xi. Appendices (if required).
11. Reporting. SNG must submit quarterly reports to the Director that: (1) include all available
data and results of the testing and evaluations required by this Order; and (2) describe the
progress of the repairs or other remedial actions being undertaken. The first quarterly report
is due on July 15, 2026, covering the period through July 1, 2026. The Director may change
the interval for the submission of these reports.
12. Documentation of the Costs. It is requested that Respondent maintain documentation of
the costs associated with implementation of this CAO. Include in each quarterly report
submitted the to-date total costs associated with: (1) preparation and revision of procedures,
studies, and analyses; (2) physical changes to pipeline infrastructure, including repairs,
replacements, and other modifications; and (3) environmental remediation, if applicable.
Administrative Actions
13. Approvals. With respect to each submission under this Order that requires the approval of
the Director, the Director may: (a) approve, in whole or part, the submission; (b) approve
the submission on specified conditions; (c) modify the submission to cure any deficiencies;
(d) disapprove in whole or in part, the submission, directing that Respondent modify the
submission, or (e) any combination of the above. In the event of approval, approval upon
conditions, or modification by the Director, Respondent shall proceed to take all action
required by the submission as approved or modified by the Director. If the Director
disapproves all or any portion of the submission, Respondent must correct all deficiencies
within the time specified by the Director and resubmit it for approval.
14. Extensions of Time. The Director may grant an extension of time for compliance with any
of the terms of this Order upon a written request timely submitted demonstrating good
cause for an extension.
Be advised that all material submitted in response to this enforcement action is subject to being
made publicly available. If you believe that any portion of your responsive material qualifies for
confidential treatment under 5 U.S.C. § 552(b), along with the complete original document you
must provide a second copy of the document with the portions you believe qualify for confidential



treatment redacted and an explanation of why you believe the redacted information qualifies for
confidential treatment under 5 U.S.C. § 552(b).
In your correspondence on this matter, please refer to “CPF No. 2-2026-009-CAO” and for each
document you submit, please provide a copy in electronic format whenever possible. The actions
required by this Order are in addition to and do not waive any requirements that apply to
Respondent’s pipeline system under 49 CFR Parts 190 through 199, under any other order issued
to Respondent under authority of 49 U.S.C. Chapter 601, or under any other provision of federal
or state law.
Respondent may appeal any decision of the Director to the Associate Administrator for Pipeline
Safety. Decisions of the Associate Administrator shall be final.
Failure to comply with this Order may result in the assessment of civil penalties and in referral to
the Attorney General for appropriate relief in United States District Court pursuant to 49 U.S.C.
§ 60120.
The terms and conditions of this Order are effective upon service in accordance with 49 CFR
§ 190.5.
__________________________ _______________________
Keith Coyle Date Issued
Chief Counsel
Pipeline and Hazardous Materials Safety
Administration
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