# Southern Natural Gas Company, LLC — Pipeline Special Permit

**Citation:** PHMSA-2016-0006  
**Type / status:** permit / current  
**Agency:** Pipeline and Hazardous Materials Safety Administration  
**Effective:** 2016-09-01  
**Published:** 2016-09-01

PHMSA-2016-0006, issued 2016-09-01 for Southern Natural Gas Company, LLC's gas transmission system.

## Document text

PHMSA pipeline special permit PHMSA-2016-0006. Operator: Southern Natural Gas Company, LLC. System: Gas Transmission. Issue date: 2016-09-01. Renewal: Mar 17, 2023.

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U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
SPECIAL PERMIT
Special Permit Information:
Docket Number:
Requested By:
Operator ID#:
Date Requested:
Original Issuance Date:
Effective Dates:
PHMSA-2016-0006
Southern Natural Gas Company, L.L.C.
18516
January 11 ,2016
September 1, 2016
Code Section(s):
September 1, 2016 to September 1, 2021
49 CFR §§ 192.611 (a) and (d), 192.619(a), and 192.5
Grant of Special Permit:
By this Order, subject to the terms and conditions set forth below, the Pipeline and Hazardous
Materials Safety Administration (PHMSA) Office of Pipeline Safety (OPS) grants a special
permit (PHMSA-20 16-0006) from September 1, 20 16 to September 1, 2021, to Southern Natural
Gas Company, L.L.C. (SNG) 1 waiving compliance from 49 Code of Federal Regulations (CFR)
§§ 192.6 11 (a) and (d), 192.619(a), and 192.5 for 26 special permit segments and 5.90 miles of
natural gas transmission pipeline as described in Appendix A 2 of this special permit.
I. Special Permit Segment and Special Permit Inspection Area:
States of Alabama, Georgia, Louisiana, and Mississippi
On the condition that SNG complies with the terms and conditions set forth below, this special
permit waives compliance from 49 CFR § 192.611 (a) for 26 special permit segments and 5.90
miles of natural gas transmission pipeline as described in Appendix A. This special permit
allows SNG to continue to operate each special permit segment listed in Appendix A at its
1 SNG is owned by Kinder Morgan, Inc.
2 Appendix A of this special permit lists the pipeline special permit segmetJt location (County and State), MAOP,
class location, diameter, wall thickness, grade, seam type, boundaries, and other attributes.
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current listed maximum allowable operating pressure (MAOP). The Federal pipeline safety
regulations in 49 CFR § 192.611 (a) require natural gas pipeline operators to confirm or revise the
MAOP of a pipeline segment after a change in class location.
This special permit applies to the special permit segments listed in Appendix A. Special permit
segments shall be divided into two (2) categories: Type A special permit segments and Type B
special permit segments.
Type A special permit segments include those special permit segments where there is a cluster,
as described in 49 CFR § 192.5(c), ofmore than 10 buildings intended for human occupancy in a
"class location unit" and for which the MAOP has not been confirmed in accordance with 49
CFR § 192.611 (a). Type A special permit segments must be replaced or pressure tested so that
the MAOP is commensurate with the present class location within three (3) years of issuance of
this special permit. Type A special permit segments3 total 1.54 mites of pipe as described in
Attachment A.
Type A special permit segments with pipe with integrity issues as determined by Conditions
6(c) and 14 or that have not been pressure tested in accordance with 49 CFR Part 192, Subpart J
to 1.25 times MAOP of this special permit must be replaced within two and one-half (2Y 2) years
of the grant of this special permit or within two (2) years of assessment finding.
Type B special permit segments include those special permit segments where there is a cluster,
as described in 49 CFR § 192.5(c), of I 0 or fewer buildings intended for human occupancy in a
"class location unit" and for which the MAOP has not been confirmed in accordance with 49
CFR § 192.611 . Type B special permit segments4 total 4.36 miles of pipe as described in
Attachment A.
3 There are 1.54 miles of Type A special permit segments and of this total 1.50 miles must be replaced and 0.04
miles must be pressure tested as listed on Attachment A, see Condition 16 for pressure test requirements.
4 There are 4.36 miles of Type B special permit segme11ts and 0.72 miles of this total must be pressure tested as
listed on Attachment A, see Condition 16 for pressure test requirements. One (I ) Type B special permit segment
(KM segment number 352) is a § 192.6 19(c) Grandfathered segment and wi ll require pressure testing.
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Subsequent to the issuance of this special permit, those special permit segments that have been
pressure tested or replaced such that the MAOP has been made commensurate with the present
class location as defined in 49 CFR § 192.6 11 would no longer be included in this special permit.
5
Special permit inspection area
- is defined as a one ( I) mile continuous segment on both sides
of the special permit segment (Type A and Type B) plus the footage in the special permit
segment. Appendix A lists the boundaries for the special permit inspection area associated with
each special permit segment. The SNG special permit inspection area totals 57.90 miles of pipe
as described in Attachment A.
PHMSA hereby grants this special permit for the pipeline special permit segments listed in
Appendix A based on the findings set forth in the "Special Permit Analysis and Findings "
document, which can be read in its entirety in Docket No. PHMSA-2016-0006 in the Federal
Docket Management System (FDMS) located on the internet at www.Regulations.gov.
II. Conditions:
PHMSA OPS grants this special permit subject to the following conditions:
l) Maximum Allowable Operating Pressure: SNG must continue to operate the special
permit segments at or below their existing MAOP as noted in Appendix A.
2) Integrity Management Program: SNG must incorporate the special permit inspection
areas into its written integrity management program (IMP) as a "covered segment " in a
"high consequence area (HCA) " in accordance with 49 CFR § 192.9036
.
3) Close Interval Surveys: SNG must perform a close interval survey (CIS) along the entire
5 Special permit inspection areas throughout these conditions include special permit segme11ts unless specifically
defined as not applicable or if the special permit segment has more stringent conditions.
6 SNG is not required to report the mileage included as part of this special permit in its annual report per the
requirements of 49 CFR § 191. 17, unless it is in a high consequence area.
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length of all special permit inspection areas
7 and remediate any areas of inadequate cathodic
protecti on no later than three (3) years after the issuance of this special permit. However, a
CIS need not be performed if SNG has performed a CIS and completed remediation8
including damaged coating repair along the entire length of all special permit inspection
areas Jess than seven (7) years9 prior to the issuance of this special permit. If environmental
permitting or right-of-way factors beyond SNG control should prevent the completion of the
CIS within three (3) years from the issuance of this special permit, a CIS and subsequent
remediation including coating repair must be completed as soon as practicable and a letter
justifying the delay and providing the anticipated date of completion must be submitted to the
appropriate PHMSA OPS Region Director no later than three (3) months pri or to the end of
three (3) years after the issuance of this special permit and must receive a "no objection"
from the PHMSA OPS Region Director for a delay. CIS remediation activities must be
completed within one (1) year of the finding. Any extended evaluation and remediation
schedules submitted to PHMSA from SNG must receive a "no objection" from the
appropriate PHMSA OPS Region Director to implement an extended CIS and remediation
interval.
4) Close Interval Surveys- Reassessment Interval: SNG must perform a periodic close
interval survey (CIS) of the special permit inspection areas at the applicable reassessment
interval(s) for a "covered segment" in accordance with 49 CFR Part 192, Subpart 0, for
reassessment intervals as contained in 49 CFR §§ 192.937(a) and (b) and 192.939, not to
exceed a seven (7) year reassessment interval10
• CIS data shall be integrated with in-line
inspection (ILl) data. Condition I5(b)- Data Integration - gives a complete description of
7 Each condition that requires SNG to perform an action with respect to the special permit inspection areas shall
also require SNG to perform that action on all special permit segments within such areas. T ype A special permit
segments that will be replaced within three (3) years of this special permit issuance do not require a CIS.
8 The terms "remediate" or "remediation" of pipe coating shall include repair of damaged external pipe coating,
where required to maintain cathodic protection of the pipeline in accordance with 49 CFR § 192.463.
9 lf49 CFR § 1 92.939(a) integrity management reassessment interval sho uld change·from seven (7) years to some
other reassessment interval under eig ht (8) years, SNG may use that reassessment interval instead of seven (7)
years.
10 If 49 CFR § 192.939(a) integrity management reassessment interval should change from seven (7) years to some
other reassessment interval under eight (8) years, SNG may use that reassessment interval instead of seven (7)
years.
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data integration information that an operator must maintain for a special permit in the special
permit inspection areas which includes CIS and ILl data. CIS assessments within the
reassessment interval are not required to be performed in the same year as ILl reassessments.
5) Cathodic Protection Reliability Improvement Plan: SNG shall implement a plan to
improve cathodic protection reliability and perform inspections for stress corrosion cracking
(SCC).
a) Cathodic Protection Reliability Improvement Plan
i) SNG must perform a periodic CIS of special permit inspection areas as part
of Condition 4, Close Interval Surveys, with reassessment intervals at an
increased frequency, not to exceed a seven (7) year reassessment interval
with CIS data integrated with the most-recent in-line inspection data 11
;
ii) SNG must integrate the most current CIS data with in-line inspection results
in the special permit inspection area in accordance with Condition 15(b)
timing requirements:
iii) Within 90 days of the issuance of this special permit, SNG must amend
applicable sections of its operations and maintenance (O&M) manual(s) to
prohibit future use of coating that is known to shield cathodic protection
along the entire length of the special permit inspection areas; and
iv) SNG must perform a run comparison analysis of in-line inspection results
subsequent to the baseline inspection in the special permit inspection areas
to identify areas of external corrosion growth after each new tool run when
the same in-line inspection vendor is used for consecutive inspections.
Areas with corrosion growth over 30% in depth must be remediated within
one ( 1) year of the finding or direct current voltage gradient (DCVG) survey
run to locate problem coating areas within six (6) months of the finding with
remediation completed within six (6) months of the DCVG survey.
11 lf49 CFR § 192.939(a) integrity management reassessment interval should change fTom seven (7) years to some
other reassessment interval under eight (8) years, SNG may use that reassessment interval instead of seven (7)
years.
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v) Within one ( 1) year of the issuance of this special permit, SNG must install
cathodic protection remote monitoring units (RMUs) at all impressed
current sources directly influencing the special permit segments;
vi) SNG must configure the RMUs in the special permit segments with alarms
to notify SNG immediately in the event of any interruption in cathodic
protection current output; and
vii)SNG must respond and correct any interruption in cathodic protection
current output immediately (within two (2) working days). If a systemic
issue is present, then SNG must investigate and remediate the problem
within one ( 1) month or less or SNG must receive a "no objection" from the
appropriate PHMSA OPS Region Director for issues that require longer to
remediate.
b) Stress Corrosion Cracking Inspections
i) SNG must review historical records to determine if SCC inspections have
been performed in the special permit segments and from these inspections
evaluate the threat of stress-corrosion cracking as part of the SCCDA Pre-
Assessment Step in Condition 6(a).
ii) SNG must perform magnetic particle inspection on any pipe (with the
exception of pipe coated with fusion-bonded or liquid-applied epoxy
coatings, which are not at risk for SCC) excavated in the special permit
inspection areas to evaluate the pipe for sec where disbonded coating is
removed in order to perform the inspection.
6) Stress Corrosion Cracking Direct Assessment: SNG must evaluate pipelines along the
entire length of the special permit inspection areas for sec as follows:
a) SNG must perform a stress corrosion cracking direct assessment (SCCDA) or other
appropriate assessment method for sec [such as pressure test or in-line inspection
(ILl) with a crack detection tool] of pipelines along the entire length of all special
permit inspection areas according to the requirements of 49 CFR § 192.929 and/or
NACE SP 0204-2008 no later than three (3) years after of the issuance of this special
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permit. The SCCDA or other approved method must address high pH SCC and near
neutral pH SCC. The SCCDA Pre-Assessment Step will include the results of all
close-interval surveys and coating surveys required in Conditions 3, 4, and 5.
i) If environmental permitting or right-of-way factors beyond SNG control
prevent the completion of the SCCDA survey and remediation within three
(3) years from the issuance ofthis special permit, a SCCDA and remediation
must be performed as soon as practicable and a letter justifying the delay
and providing the anticipated date of completion must be submitted to the
appropriate PHMSA OPS Region Director no later than three (3) months
prior to the end of three (3) years after the issuance of this special permit
and must receive a "no objection" from the PHMSA OPS Region Director
for a delay.
ii) SNG may eliminate this Condition 6(a), provided SNG provides an
engineering assessment showing that the pipeline does not meet the criteria
for either near neutral or high pH SCC in accordance with the applicable
edition of the American Society of Mechanical Engineers Standard B31.8S,
"Managing System Integrity of Gas Pipelines " (ASME B3 1.8S), Appendix
A3, or NACE SP 0204-2008, "Stress Corrosion Cracking (SCC) Direct
Assessment Methodology ", Section 1.2. 1.1 and 1.2.2.
iii) A SCCDA need not be performed ifSNG has performed a SCCDA of
pipelines along the entire length of the special permit inspection areas
within the timeframe for SCCDA re-assessments specified in 49 CFR Part
192, Subpart 0 , not to exceed seven (7) years
1 2 prior to the issuance of this
special permit.
b) If the SCCDA required in Condition 6(a) demonstrates SCC, SNG must directly
examine pipe in the special permit inspection areas for sec using an accepted
industry detection practice, such as dry or wet magnetic particle tests, anytime the
pipelines are exposed for any reason, including damage prevention activities. Poor
coating is coating losing adhesion to the pipe which is shown by falling off the pipe,
1 2 If 49 CFR § 1 92.939(a) integrity management reassessment interval should change from seven (7) years to some
other reassessment interval under eight (8) years, SNG may use that reassessment interval instead of seven (7)
years.
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and/or shields the cathodic protection. SNG must keep coating records13 of all
excavation locations for the special permit inspection areas to demonstrate the
coating condition.
c) If SCC14
activity is discovered by any means within the special permit inspection
area in similar pipe and pipe coating vintage [in accordance with 49 CFR
§ 192.917(e)], or has had an in service or hydrostatic test sec failure or leak; the
special permit segment must be further assessed and mitigated, using one of the
following methods, within one ( I) year of finding SCC:
i) Hydrostatic test program
A. The SCC hydrostatic test program must be performed at a
reassessment interval no greater than seven (7) calendar years (but
may be at a lesser interval in accordance with the results of an
engineering critical assessment) in the special permit segment.
B. If pipe in the special permit segment leaks or ruptures during a
hydrostatic test due to sec, all pipe in the special permit segment
must be replaced with new pipe within 18 months of the completion of
a successful SCC hydrostatic test. A successful SCC hydrostatic test
must be completed prior to returning the special permit segment to
operational service.
ii) Crack detection tool assessment
A. sec detection tool must be run in the special permit inspection area,
B. All SCC 15 cracking found in the special permit segment must be
replaced with new pipe within one (I ) year of finding sec,
iii) Operating pressure lowered to 60% of the specified minimum yield strength
(SMYS),
iv) Replace all affected pipe to meet 49 CFR § 192.6 11 in the special permit
segment.
1 3 The records must include, at a minimum, a description of the SNG 's detectio n procedures, records of finding, and
mitigation procedures implemented for the excavation.
14 " SCC" activity shall be defined as over both I 0 percent wall thickness depth and 2-inches in length.
15 ··sec· activity shall be defined as over both I 0 percent wall thickness depth and 2-inches in length.
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d) If any SCC activity is discovered in the special permit inspection area, SNG must
submit a SCC remediation plan to the appropriate PHMSA OPS Region Director with
a copy to the Director, PHMSA OPS Engineering and Research Division no later than
60 days after the finding of SCC:
i) That meets Condition 6(c), including a SCC remediation/repair plan with
sec characterization and timing, or
ii) Technical justification that shows that the threat for SCC in the special
permit segment is being addressed.
7) O&M Manual- In-line Inspections, Close Interval Survey Inspections, and
Reassessment Intervals: SNG must amend applicable sections of its operations and
maintenance (O&M) manual(s) to incorporate the in-line inspection (ILl), close interval
inspections (CIS), and reassessment intervals by the appropriate integrity assessment method
including both high resolution metal loss and deformation/geometry tools along the entire
length of the special permit inspection areas at a frequency consistent with 49 CFR Part 192,
Subpart 0 , but not to exceed a seven (7) year reassessment interval1 6
•
8) In-Line Inspection Initial Assessment: SNG must perform integrity assessments along the
entire length of the special permit inspection areas using appropriate assessment methods
based on threats identified during the risk assessment process including both high resolution
magnetic flux leakage (HR-MFL) and either HR-geometry or HR-deformation tools. If
integrity assessments have not been performed within seven (7) years prior to the issuance of
this special permit, SNG must complete initial integrity assessments along the entire length
of the special permit inspection areas within three (3) years of the issuance of this special
permit. Subsequent integrity assessments along the entire length of the special permit
inspection areas must conform to the required maximum reassessment intervals specified in
49 CFR § 192.939, but may not exceed a seven (7) year reassessment interval17
.
1 6 If 49 CFR § 1 92.939(a) integrity management reassessment interval should change from seven (7) years to some
other reassessment interval under eight (8) years, SNG may use that reassessment interval instead of seven (7)
years.
17 If 49 CFR § 192.939(a) integrity management reassessment interval should change from seven (7) years to some
other reassessment interval under eight (8) years, SNG may use that reassessment interval instead of seven (7)
years.
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9) Integrity Reassessment Intervals: SNG must schedule integrity reassessment dates for the
entire length of the special permit inspection areas according to 49 CFR § 192.939 by
adding the required time interval to the previous assessment date, but may not exceed a seven
(7) year reassessment interval 18
•
1 0) High Consequence Area Assessments: SNG must not let this special permit be a basis fo r
deferring any of its assessments for HCAs in accordance with 49 CFR Part 192, Subpart 0.
11) Annual Reports to PHMSA: Within three (3) months following the issuance of this special
permit and annually
1 9 thereafter, SNG must report the following to the appropriate PHMSA
OPS Region Director with copies to the Deputy Associate Administrator, PHMSA Field
Operations; Deputy Associate Administrator, PHMSA Policy and Programs; Director,
PHMSA Engineering and Research Division; and Director, PHMSA Standards and
Rulemaking Division:
a) The number of new residences, other structures intended for human occupancy and
public gathering areas built within the special permit segment and also within one ( I)
mile on either end of the special permit segment.
b) Any new integrity threats identified during the previous year and the results of any
ILl or direct assessments performed (including any un-remediated anomalies over
30% wall loss, cracking found in the pipe body, weld seam or girth welds, and dents
with metal loss, cracking or stress riser) during the previous year in the special permit
inspection segment.
c) Any reportable incident or any leak normally indicated on the DOT Annual Report,
and all repairs on the pipeline that occurred during the previous year in the special
permit inspection areas.
18 If 49 CFR § 192.939(a) integrity management reassessment interval should change from seven (7) years to some
other reassessment interval under eight (8) years, SNG may use that reassessment interval instead of seven (7)
years.
1 9 Annual reports must be received by PHMSA by the last day of the month in which the Special Permit is dated.
For example, the annual report for a modified Special Permit dated November, 20 1 2, must be received by
PHMSA no later than November 30, each year beginning in 20 13.
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d) Summary report of any fatigue analysis performed on all in-service, non-remediated
dents over 6% and with total strain :S 5%, as required in Condition 13(b ).
e) Annual data integration information, as required in Condition l5(b) - Data Integration
must be submitted beginning with the 2"d annual report that includes an annual
overview of any new threats, or if requested by PHMSA a fu ll information package.
f) Any mergers, acquisitions, transfer of assets, or other events affecting the regulatory
responsibility of the company operating the pipeline.
g) An updated Appendix A reflecting changes in Special Permit Segment boundaries
including extensions, deletions, or modifications.
h) In the first annual report, SNG must describe the estimated economic benefits of the
special permit including both the capital and operational costs avoided from not
replacing the pipe and the estimated incremental operational costs of any inspection
program requirements of the special permit for the 5-year grant period that are not
already being conducted by SNG through their operational procedures.
i) In the first annual report, SNG must describe whether the public benefits from energy
availability. This should address the benefits of any avoided disruptions as a
consequence of pipe replacement and the benefits of maintaining system capacity.
12) Interference Currents Control: SNG must address induced alternating current (AC) from
parallel electric transmission lines and other interference issues such as direct current (DC) in
the special permit inspection areas that may affect the pipeline. An induced AC or DC
program and remediation plan to protect the pipeline from corrosion caused by stray currents
must be in place within one (l) year of the date of this special permit.
a) At least once every seven (7) years not exceeding 90 months, SNG must perform an
engineering analysis on the effectiveness of the AC and DC mitigation measures and
must evaluate any AC interference between 20 and 50 Amps per meter squared. In
evaluating such interference, SNG must integrate AC interference data with the most
recent ILl results to determine remediation measures. Any AC interference between
20 and 50 Amps per meter squared must be remediated within six (6) months of the
finding. If SNG does not remediate AC interference between 20 and 50 Amps per
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<<<PAGE 12>>>

meter squared, SNG must provide an engineering justification for not remediating
such interference to the appropriate PHMSA OPS Region Director, who may accept
or reject the justification and require remediation.
b) In special permit inspection areas with co-located high voltage alternating current
c) d) (HYAC) power lines, SNG must take interference readings (continuous 24 hour
recordings) during the calendar quarter of the known or anticipated highest voltage
reading. If there are any significant increases to the amount of electricity/current
flowing in any co-located high voltage alternating current (HY AC) power li nes, such
as from additional generation, a voltage up-rating, additional lines, or new or enlarged
substations, SNG must perform an AC mitigation survey along the entire co-located
pipeline special permit inspection area right of way within six (6) months of any
such change.
Within six (6) months of the engineering analysis, SNG must remediate any AC
interference greater than 50 Amps per meter squared. Remediation means the
implementation of performance measures including, but not limited to, additional
grounding along the pipeline to reduce interference currents. Any DC interference
that results in CP levels that do not meet the requirements of 49 CFR Part 192,
Subpart I, must be remediated within six (6) months of this evaluation.
If environmental permitting or right-of-way factors " beyond SNG control" prevent
the completion of remediation within six ( 6) months of the interference evaluation.
remediation must be completed as soon as practicable and a letter justifying the delay
and providing the anticipated date of completion must be submitted to the appropriate
PHMSA OPS Region Director no later than one ( 1) month prior to the end of the six
(6) months completion date. Any extended evaluation and remediation schedules
submitted to PHMSA from SNG must recei ve a "no objection" from the appropriate
PHMSA OPS Region Director.
13) Anomaly Evaluation and Repair:
a) General: SNG must account for ILl tool tolerance and corrosion growth rates in
scheduled response times and repairs and document and justify the values used. SNG
must demonstrate ILl Tool tolerance accuracy for each ILl Tool run by usage of
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<<<PAGE 13>>>

b) calibration excavations and unity plots that demonstrate ILl Tool accuracy to meet
the tool accuracy specification provided by the vendor (typical for depth within
+ 10% accuracy for 80% of the time). The unity plots must show: a) actual anomaly
depth versus predicted depth and b) actual failure pressure/MAOP versus predicted
failure pressure/MAOP. Discovery date must be within 120 days of an ILl Tool run
for each type ILl Tool (HR-geometry, HR-defonnation, or HR-MFL).
i) ILl tool evaluations for metal loss must use "6t x 6t" interaction cri teria (or
more conservative criteria) for detennining anomaly failure pressures and
remediation response timing with " 61" being pipe wall thickness times six.
Dents: SNG must repair dents in the special permit segment and special permit
inspection area in accordance with 49 CFR § 192.933 if it is located in a HCA and in
accordance with 49 CFR §§ 192.933(a)-(c) repair criteria and "Table 1 - Special
Requirements for Scheduling Remediation" if it is not located in an HCA.
Table 1 -Special Requirements for Scheduling Remediation
Required Response Required Response
Defect Type Orientation Special Permit Special Permit
Segment Inspection Area
Top or Bottom Immediate Immediate
Dent Associated with
Cracks or Stress Risers
Dent Associated with
Top or Bottom l Year Scheduled 2 Year Scheduled
Metal Loss
Plain Dent > 6 % OD
Deep or that exhibits Top 1 Year Scheduled 2 Year Scheduled
total strain > 5 %
Plain Dent > 2% OD
Deep Associated with Top or Bottom l Year Scheduled 2 Year Scheduled
Girth or Seam Weld
Plain Dent > 6 % OD
Deep and that exhibits Top or Bottom Monitored Monitored
total strain ~ 5 %
Plain D
ent
~ 2% OD
Deep Associated with Top or Bottom Monitored Monitored
Girth or Seam Weld
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<<<PAGE 14>>>

Definitions
I. Plain Dent - Dent without metal loss, crack or stress riser.
2. Immediate Response - Reduce pressure to 80% of recent maximum pressure. Immediate
dents require an immediate pressure reduction and I or restriction and examination and
remediation as required in conformance with SNG requirements within fi ve (5) calendar
days from the date of discovery. If the remediation cannot be met according to the
response schedule, a technical justification must be prepared that explains the reasons why
the schedule cannot be met and indicate how the changed schedule will not jeopardize
public safety. Any extended response schedules must be submitted to PHMSA from SNG
within 14 days of pressure reduction after discovery and must receive a "no objection"
from the appropriate PHMSA OPS Region Director.
3. Scheduled Response - Schedule excavation within an appropriate time frame based on the
opinion of the SME (not to exceed 365 days for special permit segments and 730 days for
special permit inspection areas).
4. Monitored - Catalog data for future monitoring.
5. Top - located between 8 o'clock and 4 o'clock positions (upper 2/3 of the pipe).
6. Bottom - located between 4 o'clock and 8 o'clock positions (bottom 1/3 of pipe).
Special permit segments and special permit inspection areas must have a HR-
geometry or HR-deformation tool inspection as part of the initial ILI or these ILI
inspections must be completed within two (2) years after issuance of this special
permit. All dent repairs must be made in accordance with 49 CFR §§ 192.933(a)
through (c) repair criteria and "Table 1 - Special Requirements for Scheduling
Remediation" on page 13 of 24. SNG must conduct the following fatigue analysis of
dents in special permit segments and special permit inspection areas:
i) SNG must conduct a fatigue analysis of all in-service, non-remediated dents
above 6% and with total strain $ 5% after each high resolution MFL and
high resolution caliper or deformation ILl evaluations. Dent fati gue analysis
must include as a minimum the following: gross geometry of dent;
orientation of dent; soil cover and type; pressure and temperature; including
cycles; and stress and strains caused by terrain. The fatigue analysis must
be completed within the time frames in "Table 1 -Special Requirements for
Scheduling Remediation" of this special permit.
ii) The overall remaining fatigue life of all in-service, non-remediated dents
over 6% and with total strain $ 5% must be either twice the designated
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<<<PAGE 15>>>

remaining life of the pipeline or at least 500 years.
c) Investigation and Repair Criteria: In-line inspection anomalies in the special
permit inspection areas with a safe pressure less than MAOP (e.g. Failure Pressure
Ratio (FPR) < 1.39) or an anomaly depth greater than 80% of pipe wall thickness
require an immediate pressure reduction and/or restriction and continuous action until
the anomaly is examined, evaluated, and remediated.
d) Response Time for ILl Results: SNG will follow Kinder Morgan O&M Procedure
916 (In-Line Inspections)20 for excavating, investigating, and remediating anomalies21
based on ILl data results in accordance with 49 CFR §§ 192.485 and 192.933. SNG
must evaluate ILl data by using either the ASME Standard B31 G, "Manual for
Determining the Remaining Strength of Corroded Pipelines " (ASME 831 G), the
modified 831 G (0.85dL), or R-STRENG for calculating the predicted FPR to
determine anomaly responses ..
• Special permit segments and special permit inspection areas:
- Immediate response: Any anomaly within a special permit segment and
special permit inspection areas operating up to 72% SMYS that meets either:
(I) an FPR equal to or less than 1.1 ; or (2) an anomaly depth equal to or
greater than 80% wall thickness loss.
- One-year response: Any anomaly within a special permit segment and
special permit inspection areas with original Class I location pipe in a Class
3 location (cluster area) operating up to 72% SMYS that meets either: (1) an
FPR less than 1.39; or (2) an anomaly depth greater than 40% wall thickness
loss.
- Monitored response: Any anomaly within a special permit segment and
special permit inspection areas with original Class 1 location pipe in a Class
3 location (cluster area) operating up to 72% SMYS that meets both: (1) an
FPR equal to or greater than 1.39; or (2) an anomaly depth less than or equal
to 40% wall thickness loss.
e) Special permit segments and special permit inspection areas: Upon issuance of this
20 The requirements of this Special Permit and 49 CFR §§ 192.485 and 192.933 supersedes Kinder Morgan O&M
Procedure 916 (In-Line Inspections).
21 The timing intervals for dent remediation in non-HCAs are in Condition 6(b).
PHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 15 of27

<<<PAGE 16>>>

special permit, SNG must implement the repair and remediation of any pipe
anomalies or dents that are not in compliance with Condition 13 based upon existing
ILl assessment results from the high resolution MFL and geometry/deformation tools
used to previously assess pipelines in the special permit segments and special permit
inspection areas. SNG must review existing ILl assessment results within 18 months
from the issuance of this special permit according to the following schedule: 30% of
pipelines in the special permit segments and special permit inspection areas must be
reviewed within six (6) months of the issuance of this Special Permit, 65% of
pipelines in the special permit segments and special permit inspection areas must be
reviewed within 12 months of the issuance this special permit, and I 00% of pipelines
in the special permit segments and special permit inspection areas must be reviewed
within 18 months of the issuance of this Special permit. Anomalies and dents
discovered during this review must be remediated in accordance with Condition 13
timing requirements.
14) Pipe Seam Evaluations:
a) SNG must identify any pipe in the special permit segment that may be susceptible to
pipe seam issues because of the vintage of the pipe, the manufacturing process of the
pipe, or other issues. Once SNG has identified such issues, SNG must complete
Condition 14(a). If the engineering analysis required in Condition 14(a) reveals that
there is a threat to the pipeline, then SNG must complete all of the applicable
condition requirements in Condition 14(a)(ii), (a)(iii), (a)(iv), (a)(v), (a)(vi), (a)(vii),
and (a)(viii):
i) SNG must perform an engineering analysis to determine if there are any
pipe seam threats on pipelines located in the special permit segment. This
analysis must include the documentation that the processes in ' M Charts' in
"Evaluating the Stability of Manufacturing and Construction Defects in
Natural Gas Pipelines" by Kiefner and Associates updated April 26, 2007,
under PHMSA Contract DTFAA-COSP02120 and Figure 4.2, ' Framework
for Evaluation with Path for the Segment Analyzed Highlighted· from TT0-
5 "Low Frequency ERW and Lap Welded Longitudinal Seam Evaluation" by
PHMSA-2016-0006 - Southern Natural Gas Company Special Permit Page 16 of 27

<<<PAGE 17>>>

Michael Baker Jr., and Kiefner and Associates, et. at. under PHMSA
Contract DTRS56-02-D-70036 were utilized along with other relevant
materials. If the engineering analysis shows that the pipe seam issues on
pipelines located in the special permit segment are not a threat to the
integrity of the pipeline, SNG does not have to complete Conditions l4(a)
(ii) through (vii), but must complete Conditions 14(a)(viii) and (ix).
ii) If a 49 CFR Part 192, Subpart J hydrostatic test has not been performed, the
special permit segments must be hydrostatically tested to a minimum
pressure of 100 percent SMYS, in accordance with 49 CFR Part 192,
Subpart J requirements for eight (8) continuous hours, within two and one-
half (21 /2) years of issuance of this special permit. The hydrostatic test must
confirm no systemic issues with the weld seam or pipe. A root cause
analysis, including metallurgical examination of the failed pipe, must be
performed for any failure
22 experienced to verify that it is not indicative of a
systemic issue. The results of this root cause analysis must be reported to
the appropriate PHMSA Region Director with a copy to the Director,
PHMSA Engineering and Research Division, within 60 days of the failure.
iii) Special permit segments with low frequency electric resistance welded (LF-
ERW) pipe with a history of leaks or failures without a "spike test" within
the special permit inspection area must be pressure tested23 with a "spike
test" within two and one-half (2 Y2) years of the issuance of this special
permit.
iv) Special permit segments24 with pressure tests less than 1.25 times MAOP
that may be susceptible to pipe seam issues must be tested with a Subpart J
pressure test within two and one-half (2 Y2) years of issuance of this special
22 A root cause analysis, including metallurg ical examination of the pipe, must be performed for any leaks that are
removed from the special permit segment.
23 A root cause analysis, including metallurgical examination of the pipe, must be performed for any pressure test
fai lures or leaks from the special permit segment.
24 SNG must implement the replacement of all Type A special permit segments as defined on page 2 of this special
permit as noted: " Type A special permit segments with pipe with integrity issues as determined by Conditions 6
and 14 or that have not been pressure tested in accordance with 49 CFR Part 192, Subpart J to 1.25 times MAOP
of this special permit must be replaced within two and one-half (2 Y:z) years of the grant of this special permit or
within two (2) years of assessment finding."
PHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 17 of27

<<<PAGE 18>>>

permit or the pipe must be replaced with pipe that meets§ 192.619 within
two and one-half (2 \12) years of issuance of this special permit. If the pipe is
then commensurate with the Class location in accordance with
§ 192.6 1l(a)(3)(i i) the segment is no longer part of this Special Permit.
v) If the pipeline in the special permit inspection area has experienced a seam
leak or failure in the last fi ve (5) years and no hydrostatic test meeting the
conditions of 49 CFR Part 192, Subpart J was performed after the seam leak
or failure, then a hydrostatic test must be performed within two and one-half
(2Vz) years after the issuance of this special permit on the special permit
segment pipeline25
; or
vi) If the pipeline in any special permit segment has pipe seam conditions as
noted below in (A), (B), or (C), such special permit segment pipeline shall
not be eligible for this special permit:
A) has unknown manufacturing processes without the greater of a 49 CFR
Part 192, Subpart J hydrostatic test or a 1.25 times MAOP pressure
test, or
B) has low fracture toughness pipe that wi ll not ensure ductile fracture
and arrest, or
C) has known manufacturing or construction issues that are unresolved
[such as concentrated hard spots, hard heat-affected weld zones,
selective seam corrosion, pipe movement that has led to buckling, have
had past leak and rupture issues, or any other systemic issues).
vii) If the pipeline in any special permit segment has a reduced longitudinal
joint seam factor, below 1.0, as defined in 49 CFR § 192. 11 3 the special
permit segment pipeline must be replaced.
viii) Pipe in the special permit segments must have all weld seam or girth weld
repairs that have been made by the usage of fittings such as wei do lets,
threadolets, repair clamps and pipe sleeves removed and replaced with pipe
in accordance with 49 CFR Part 192 requirements.
25 A root cause analysis, including metallurgical examination of the pipe, must be performed for any pressure test
failures or leaks trom the special permit segment.
PHMSA-2016-0006 - Southern Natural Gas Company Special Permit Page 18 of27

<<<PAGE 19>>>

b) SNG must submit a seam remediation plan for the special permit segments to the
appropriate PHMSA Region Director no later than 30 days after finding a seam leak
in the special permit segment:
i) Longitudinal weld seam remediation/repair plan that meets Condition 14(a)
and includes either replacement, hydrostatic testing, or in-line inspection
(ILl), and timing of the plan not to exceed six (6) months, or
ii) Technical justification that shows that the special permit segment is not at
risk for future longitudinal seam leaks or failures.
15) Special Permit Segment Specific Conditions: SNG must comply with the following
requirements.
a) Line~of-Sight Markers: SNG must install and maintain line-of-sight markings on the
pipeline in the special permit inspection areas except in agricultural areas or large
water crossings such as lakes where line-of-sight signage is not practical. Line-of-
sight markers must be installed within three (3) months of issuance of this special
permit and replaced as necessary by SNG within 30 days after identification.
b) Data Integration: SNG must maintain data integration of special permit condition
findings and remediation in the special permit inspection areas. Data integration
must include the following information: Pipe diameter, wall thickness, grade, and
seam type; pipe coating; maximum allowable operating pressure (MAOP); class
location (including boundaries on aerial photography); high consequence areas
(HCAs) (including boundaries on aerial photography); hydrostatic test pressure
including any known test failures; casings; any in-service ruptures or leaks; in-line
inspection (ILl) survey results including HR-MFL, HR-geometry/caliper or
deformation tools; close interval survey (CIS) surveys - most recent; rectifier
readings; cathodic protection test point survey readings; AC/DC interference
surveys; pipe coating surveys; pipe coating and anomaly evaluations from pipe
excavations; stress corrosion cracking (SCC) excavations and findings; and pipe
exposures from encroachments. Data integration must be outlined on pipeline route
drawings with parallel sections for each integrity category and recent aerial
photography (recent photography, within three (3) years of initial filing and every
PHMSA-2016-0006 - Southern Natural Gas Company Special Permit Page 19 of 27

<<<PAGE 20>>>

c) three (3) years thereafter).
i) Data integration documentation and drawings to meet Condition 15(b) must
be completed and must be submitted, if requested by PHMSA, beginning
with the 2"d annual report of this special permit with four (4) years of prior
data.
ii) Data integration must be updated on an annual basis and with at least an
annual review of integrity issues to be remediated.
Pipe Properties Testing: SNG must test pipe in each special permit segment that
does not meet Condition 16(b) as follows:
i) Develop and implement procedures for conducting non-destructive or destructive
tests, examinations, and assessments for special permit segments without pipe
material records within 12 months of issuance of this special permit;
ii) A minimum of two (2) destructive or non-destructive test methods must be
performed at an excavation site for each special permit segment. For each
special permit segment, SNG will conduct one ( 1) non-destructive yield test
assessment using TD Williamson test procedures and ball indention
methodologl6
, or equivalent, and secondly, confirm yield strength through
diameter tape measurements. Should non-destructive testing of pipe material
properties show that the pipe wall thickness is not within API 5L specification
tolerances and the pipe grade is under the strength requirements of APl SL by
three (3) KSI or more, then the yield strength of that individual pipe shall be
confirmed using destructive test methods or the special permit segment pipe
must be removed within 18 months of issuance of this special permit.
Acceptance limits for the diameter tape measurements shall be in accordance
with PHMSA Advisory Bulletin ADB-09-0 l.
iii) Assessments must be made for each unique combination of the following
attributes with missing mill test reports (MTRs) or mill inspection reports (i.e.
Moody Engineering Reports): wall thicknesses (within 10 percent ofthe smallest
wall thickness in the population), grade, manufacturing process, pipe
26 Non-destructive assessment method and procedures must be submitted to PHMSA OPS Region Director and
PHMSA OPS Director of Engineering and Research Division for review and "no objection."
PHMSA-2016-0006 - Southern Natural Gas Company Special Permit Page 20 of27

<<<PAGE 21>>>

manufacturing dates (within a two (2) year interval) and construction dates
(within a two (2) year interval).
iv) The material properties determined from either destructive or non-destructive
tests required by this Condition cannot be used to raise the original grade or
specification of the material, which must be based upon the applicable standard
referenced in 49 CFR § 192.7.
v) For future special permit segments with missing MTRs or mill inspection
reports, the above methodology shall be applied or SNG may elect to remove
pipe joints for destructive testing27
. Such testing shall be performed within one
( I) year of identification of the new special permit segment.
d) Pipeline System Flow Reversals: For long term pipeline system flow reversals
exceeding 90 days where either49 CFR § 192.6 19(a)( I) or§ 192.611 MAOP for
class location changes are exceeded28 in a special permit segment, SNG shall prepare
a written plan that corresponds to those applicable criteria identified in PHMSA
Advisory Bulletin (ADB-20 14-04), "Guidance for Pipeline Flow Reversals, Product
Changes and Conversion of Service" issued on September 18, 2014 (79 FR 5612 1,
Docket PHMSA-20 14-0400). The written flow reversal plan must be submitted to
the appropriate PHMSA OPS Regional Director with a copy of the plan submitted to
the Federal Docket for this special permit at www.regulations.gov. SNG must
receive a "no objection" from the appropriate PHMSA OPS Region Director prior to
implementing the pipeline system flow reversal through the special permit segment.
e) Environmental Assessments and Permits: SNG must evaluate the potential
environmental consequences and affected resources of any land disturbances and
water body crossings needed to implement the special permit conditions for a special
permit segment or a special permit inspection area prior to the disturbance. If a
land disturbance or water body crossings is required, SNG must obtain and adhere to
all applicable (Federal, State, and Local) environmental permit requirements when
conducting the special permit conditions activity.
21 SNG must prepare a procedure in accordance with Condition IS( c) for material documentation and submit to
PHMSA ' s OPS Region Director for "no objection''.
28 An example of exceedance of 49 CFR § 192.619(a)( I) is a Grand fathered MAOP which has a design factor above
0. 72. An example of exceedance of 49 CFR § 192.6 1 I is a Class I to 3 location change.
PHMSA-2016-0006 - Southern Natural Gas Company Special Permit Page 21 of27

<<<PAGE 22>>>

16) Documentation: SNG must maintain the following records fo r each special permit segment
and special permit inspection areas:
a) Documentation showing that each special permit segment has received a 49 CFR
§ 192.505, Subpart J, hydrostatic test for eight (8) continuous hours and at a
minimum pressure of 1.25 times MAOP (1.25 x MAOP). If SNG does not have
hydrostatic test documentation, then:
Type A special permit segments must be hydrostatically tested to meet this
requirement within two and one-half (2 ~) years of the issuance of this special
permit, and
Type B special permit segments must be hydrostatically tested to meet this
requirement within three (3) years of the issuance of this special permit.
b) Documentation of mechanical and chemical properties including pipe toughness (mill
test reports) showing that the pipe in each special permit segment meets the wall
thickness, yield strength, tensile strength and chemical composition of either the
American Petroleum Institute Standard 5L, 5LX or 5LS,
"Specificationfor Line
Pipe " (API 5L) referenced in the 49 CFR Part 192 code at the time of manufacturing
or if pipe was manuf actured and placed in-service prior to the inception of 49 CFR
Part 192 then the pipe meets the API 5L standard in usage at that time.
c) Documentation of compliance with all the conditions of this special permit must be
kept for the applicable life of this special permit for the referenced special p ermit
segments and special permit inspection areas.
17) Extension of Special Permit Segments: PHMSA may extend each original Type B special
permit segment to include contiguous segments of pipeline on either side of the Type B
special permit segment where, following the issuance of this special permit, an increase in
population density indicates a change in class location. Type A special permit segments may
not be extended. Type B special permit segments may not be extended if the extension
would redefine the extended segment as a Type A special permit segment as described in
Section I of this special permit. SNG must:
a) Provide notice to the Director, PHMSA OPS Standards and Rulemaking Division;
Director, PHMSA OPS Engineering and Research Division; and appropriate PHMSA
PHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 22 of27

<<<PAGE 23>>>

OPS Region Director of a requested special permit segment or extension19 based on
actual class location change and include a schedule of inspections, of any anticipated
remedial actions and the location of the new request including survey stationing. All
requests for a special permit segment or extension must be submitted in the first nine
(9) months ofthe 49 CFR § 192.61 1(d) timing limits, and must include data
integration (see Condition lS(b )) and information on the potential environmental
impacts of the extension to determine whether an environmental assessment is
required for the special permit segment extension.
b) Complete all inspections and remediation of the proposed special permit segment
extension to the extent required of the original special permit segment.
c) Comply with all the special permit conditions and limitations included herein to all
future special permit segments or extensions.
d) New Type A special permit segments created following the grant date of this special
permit must be replaced or pressure tested so that the MAOP is commensurate with
the present class location as defined in 49 CFR § 192.6 1 1 within two (2) years of the
class location change.
e) Comply with all conditions of this special permit for the contiguous new special
permit segments or extensions required for implementation and certification in
accordance with 49 CFR § 192.611 (d) timing limits, including submittal of
documents to PHMSA required in Condition 18 - Certification.
18) Certification: A senior executive officer, vice president or higher, of SNG must certify in
writing the following:
a) SNG pipeline special permit inspection areas and special permit segments meet the
conditions described in this special permit,
b) The written manual of O&M procedures (required by§ 192.605) for the SNG
pipeline has been updated to include all additional requirements of this special permit;
and
c) SNG has implemented all Conditions as required by this special permit.
29 For a new special permit segment or extension to be considered by PHMSA, SNG must notify the appropriate
PHMSA OPS Region Director to determine the need for a draft environmental assessment.
PHMSA-2016-0006 - Southern Natural Gas Company Special Permit Page 23 of27

<<<PAGE 24>>>

SNG must send the certifications required in Condition 18(a) through (c) with completion
date, compliance documentation summary, and the required senior executive signature and
date of signature to the PHMSA OPS Associate Administrator with copies to the Deputy
Associate Administrator, PHMSA OPS Policy and Programs; appropriate PHMSA OPS
Region Director; Director, PHMSA OPS Standards and Rulemaking Division; Director,
PHMSA OPS Engineering and Research Division; and to the Federal Register Docket
(PHMSA-2016-0006) at www.Regulations.gov within one (1) year of the issuance date of
this special permit.
III. Limitations:
PHMSA modifies this special permit subject to the following limitations:
1) PHMSA has the sole authority to make all determinations on whether SNG has complied
with the specified conditions of this special permit.
2) Failure to submit the certifications required by Condition 18 within the time frames specified
may result in revocation ofthis special permit.
3) PHMSA may revoke, suspend or modify a special permit based on any finding listed in 49
CFR § 190.34 1 (h)(l ) and require SNG to comply with the regulatory requirements in 49
CFR § 192.611. As provided in 49 U .S.C. Chapter 601 and 49 CFR Part 190, PHMSA may
also issue an enforcement action for failure to comply with this Order. Any work plans and
associated schedules shall be automatically incorporated into this order and are enforceable
in the same manner.
4) Should PHMSA revoke, suspend, or modify a special permit under 49 CFR § 190.34 1 (h)( I),
PHMSA will notify SNG in writing of the proposed action and provide SNG an opportunity
to show cause why the action should not be taken. In accordance with 49 CFR
§ 190.341 (h)(3), if necessary to avoid the risk of significant harm to persons, property, or the
environment, PHMSA will not give advance notice and will declare the proposed action
(revocation, suspension, or modification) immediately effective.
5) The terms and conditions of any corrective action order, compliance order or other order
PHMSA-2016-0006 - Southern Natural Gas Company Special Permit Page 24 of27

<<<PAGE 25>>>

applicable to a pipeline facility covered by this special permit will take precedence over the
terms of this special permit in accordance with 49 CFR § 190.341 (h)( 4).
6) If SNG sells, merges, transfers, or otherwise disposes of the assets known as the special
permit segments or the special permit segment extension, SNG must provide PHMSA with
written notice of the transfer within 30 days of the consummati on date. In the event of such
transfer, PHMSA reserves the right to revoke, suspend, or modify the permit if the transfer
consti tutes a material change in conditions or circumstances pursuant to 49 CFR
§ 190.341 (h)( l )(ii) or any other circumstances listed under 49 CFR § 190.341 (h)( 1 ).
7) PHMSA grants this special permit to limit it to a term of no more than fi ve (5) years from the
issuance date. lf SNG elects to seek renewal of this special permit, as modified, SNG must
submit its renewal request at least 180 days prior to expiration o f the five (5) year period to
the PHMSA Associate Administrator with copies to the Deputy Associate Administrator,
PHMSA Policy and Programs; appropriate PHMSA OPS Region Director; Director, PHMSA
OPS Standards and Rulemaking Division; and Director, PHMSA OPS Engineering and
Research Division. PHMSA will consider requests for a special permit renewal for up to an
additional five (5) year period. All requests for a special permit renewal must include a
summary report in accordance with the requirements in Condition 11 (Annual Report) above
and must demonstrate that the special permit is still consistent with pipeline safety. PHMSA
may seek additional info rmation from SNG prior to granting any request for special permit
renewal.
AUTHORITY: 49 U.S.C. 60118 (c)(1) and 49 CFR § 1.97.
Issued in Washin ton, DC, on September 1, 20 16.
Liki'
Alan K. Mayberry
Acting Associate Administrator for Pipeline Safety
PHMSA-2016-0006 - Southern Natural Gas Company Special Permit Page 25 of27

<<<PAGE 26>>>

Attachment A: Listing of Southern Natural Gas Special Permit Segments
UneNanw
SOUTHERN
~(fi.N
SOlJTHE RN
SOlffitERN
SOUTHERN
SOUTIURN
SOOTltE RN
sotllllE R N
SOUTlUR N
SOUTHERN
SOUllUA N
SOUTHERN
SOUTHE RN
SOUTHE RN
SOUTHER N
SOUTHWEST
SOUTHWBT
!oOUTHW(ST
SOIITHWBT
Al
Al
Al
Al
Al
Al
Al
Al
GA
GA
GA
GA
GA
GA
GA
lA
AIJTAUGA
ALITA""'-
LEE
AUlAUGA
AUTAUGA
AUT AUG"
ll£
lEE
HARRIS
HARRIS
JONU
JON[.S
HAR RIS
liARRIS
SPALDING
ASCENSION
lA .lSCENStON
SOOT~ MAIN 2ND LOOP urn
~~ t.1AIN 1N0 lOOP Ut4 E
SOUTH Mo\IN 2ND LOOP LINE
SOUTH ~IN UN[
SO\f'n t MAIN LOOP LI N E
SOU'Ht MAIN LOOP U N£
SOUTH MAIN LOOP UN£
SOUTH MAIN lOOP UN£
SOUT" M.,IN 2ND L OOP LINE
SOUnt MAIN 2ND LOOP liNE
SOUTHW£.ST
10
11
12
13
14
1S
16
" ,.
19
lO
21
22
2l
2•
2S
26
10
..
ss
..
S9
63
64
6S
91
92
SOUnt MAIN 2N D LOOP UN£
SOVTH MAIN LI NE
SOVTU MAIN lOOP UN£
SOl!TH MAIN l OOP LIN E
THOM45T0N GRIFFIN 2ND LOOP UN£
DUCIC LAKE f AANKUNTON UN£
OUC. K LAKE fRANKUNTON UN£
lA £AST8ATON AOUG£
lA
UVINGSTON
DUCK lAKE fRAU KLINT ON UN[
DUCK LAKE fRANKliNTON UN£
ASCE N SION
WHIT£ CASfl[ fRMHCUNTON l OOP UNE
0210- 1896
02ll-St.84
0296· 1974
0211 · 50S8
0210- 1903
0211· 5149
0294·0
0196· 2030
o:m. uu
0313· 1543
Ol84 .)967
0384· 4241
030S· 4746
031.3· 1634
0027-4119
0039 · SOl
0039· 4584
00t7· 264
0071 · 1491
0039 · 431
0210· 3>60
02U· 81!10
0296 · 2486
02U· 0908
0210· 3S74
02U· 877
0294 · 662
0296· 3J22
0l06·
,..
Olll· lS46
0)3.1 · 4170
0384 . 4441
OJOEi · 1.59
OlU · 17!»9
0027 · 4296
0039· 4546
00)9· S21!0
0047· 969
0071· 2447
A
B
0209 · 1712
0210- 5184
0295· 20Sl
0210-5053
Q20C) . 2141
02W· 5149
0291· 96
Q29S. 231S
mor.- q ll
OJU · 1 S41
OJal. 4227
QJSJ. 4241
OJCW. 4756
Ol12· 16)4
0026· 4069
0033· SOl
00Ja- 4W
0046· 264
00:}10· 1491
0038 - 469
SOUTHWEST
SOUTHWEST
SOUTHERN
SOUTHERN
SOUTHERN
!oOUTHWtST
93
..
97
..
..
119
m
3S3
3SS
lA
lA
ASC[ NSION
WHIT[ CASl'U rRAN KUN TO N LOOP UN [
lA [AST BATO N ROUGE WHIT£ CASn£ fR.ANKU NTON LOOP U N£
MS SIMPSON SOt.flH MAIN lOOP liN£
MS
Al
lA
SI~SO
SOUTH Mo\IN UNE
N
AUTAIJG.4
SOUTH Mo\IN UNf
UVINGSTON
WHIT£ CASni fR.ANKUNTON LOOP UN[
0019 · 4608
00.0·768
OCXJ7 · 371
OCIJ7 · 363
0210· 1193
0039· 4546
00)9· 5220
0041· 927
0038· 4596
0046· 768
C007 · 1SS3
OCIJ7 · 1.548
02W· lS67
0071 · Wl
0071· l9S4
IXX)6 - 171
IXX)6.)6]
0209 · 189}
00:}10- L2S9
Willil1
OSAW· Double Submerccd Arc Wtld
SAW- Subme r1ed AfC Weld
FW · fl~
h Weld
[ RW-HF · Ele ctric Rulst•nce Weld · Hi&tl Frequenty
HSAW · Hehul Subtnerted Arc Weld (Spu"ll prpe)
SM.~· 'S.um.leu
NLP ·'No t Ute Prpe-' fOf Le•\.s
NSLP · ' tlon·SuKeplrble loutron 01 Pipe' for SCC
PIA · Potentr• l lmp.Kt Rldrus
MAOP- Pl. 'tiix rmum Allow•ble Operat m1 Pr essure
MLV • M<lr nline V~olve
lll1ill
s
L W'hen • sument hi S m ult rple prpe • tuibute) (test pressure, se•m. co1tr n1 . etc.), the • ttrr butt!i fot the wuhst
pipe e lement rs dapllryed
2. The Actulllenath of the ~eci•l petmr t \.e&ment ftom be&m st•tron to er~d st•t ron m• v be 1re•ter th•n the lencth
not meetrn,pre \C!nt d•n due to mmpll•nt pipe rn the w-cment
3. Prpelrnt" \tltlonrn& )Ubjt!ctto dl•n1e due to ' 1111on equ•tront, cent
e~lrne c:h•nces, e tc.
HCA- Hr&h Conseq!Jenct" Are•
SCC1
• St re\S Corrotlon Cr•d-'nl · Sellkole Inspection
SCCl • StreuCorrotlon (rK .. in& • Hyd roiUt f lrlute
5((1
• St reu(onotron (IH. .. In& • tn·Ser'i'ct f11lure
SCC' • Stren CorrotrOn Crild.t"C · Sprri.l Permrt st&ment IO<Ated 1n upnre•m comproe uor se1ment hom SC( lndu: .. hon (wrthin 20m1les), Secment deemed not susceptr~e to SCC
SSWC • SeleaiYe ~•m Weld Conos•on
MPS-Mll
~
•mum Preuurein SVu~ Prea-drnl7/ l/1910
06/"YJ/2016 re\1
Special Permit: PHMSA-2016-0006- Southern Natural Gas Company
0211· 1561
0113· 8!0
02'91-
21~
0213 · 9015
0211 · 3S74
0213 · 874
0295 - 816
0297 - 3402
0301 · )6S
0314 · .lS46
0385· uss
0385· 4Al1
Ol07 · J9
0314 · )759
0021· 4)91
oo.t0· 4S46i
oo.tO · S2!0
0011 · 969
0072 - 2.147
(X).*l- 4S42
0040· S216
0011 · 9(11
~-
l.SS1
0008- 1548
0211 · .)561
0072 · 1954
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
Special Permit Docket: PHMSA-2016-0006
N/A
N/A
N/A
N/A
tJ/A
N/A
N/A
U/ A
N/A
N/A
N/A
N/A
fJ/A
N/A
N/A
N/A
.,.
., .
N/A
.,.
N/A
N /A
N/A
.,.
.,.
., .
l221L7J
11S16 46
11 072.ll
11690.2
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10759.57
11252.]
1268S .49
10736 .67
14(:05 29
ll256lS
11264 5-I
1151&.17
1462,86
11172.3S
tona:n
1174l92
11744 74
112l38l
11291.34
167173
976.46
m
lll0.2
t6JL 71
0
m
11 .302
976.46
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1 .55&27
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ll9L96
796.<>1
l002.97
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OPID 18516
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1184 . 74
1184.74
1673..81
167311
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711 )4
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18
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24
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lO
lO
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" 24
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18
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ll.Ul..M
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f OOTAGE
MILlAG(
1200
1200
1200
1200
120?
1200
1200
1200
120?
120?
120?
120?
120?
120?
1200
1200
120?
120?
LlOO
120?
120?
uoo
120?
120?
llOO
LlOO
Page 26 of27

<<<PAGE 27>>>

Attachment A: Listing of Southern Natural Gas Special Permit Segments
Oistllnte: to MlV
PHMSA
No.
KMNo.
Toot
Pressure
(psi I)
Pipe Desl1n
Pre" ure t/1
0.72(psll)
Pipe Wall
Thldmen
(In)
PIR(ft)
Pi pe Gowle (p•il)
Pipe Seam Plpe C o.tlnl
Typo
Pipe
Installation
9
10
II
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
10
S4
55
56
59
63
64
65
91
92
93
94
97
98
99
129
352
353
355
1596
1596
1585
1637
1594
1594
1584
1584
1591
1558
1655
1648
1591
1616
15!9
1609
1609
1609
1609
1694
1694
1694
1320
1280
1637
1690
126t44
1526.4
1161..44
1197.92
1266.72
1266.72
1266.72
1266.72
1261.44
1246.15
1315.08
1315.08
1266.72
1287.94
1205.57
1287.94
1287.94
1287.94
1287.94
1238.4
1238.4
1238.4
1266.12
1297.92
1297.92
1261.44
0.438
0.53
0.438
0312
0.406
0.406
0.406
0.406
0.438
0.375
0.281
0.281
0.406
0.344
0.322
0.344
0.344
0.344
0.344
0.144
0.344
0.344
0406
D-312
0.312
0.438
717
717
717
430
574
574
574
574
717
621
382
382
574
478
478
478
478
478
478
574
574
574
574
430
430
717
60000
60000
60000
52000
52000
52000
52000
52000
60000
60000
52000
52000
52000
52000
52000
52000
52000
52000
52000
60000
60000
60000
52000
52000
52000
60000
--
SAW COAL TAR ENAMEl
SAW COAL TAR ENAMEl
SAW COAL TAR ENAMEl
FW COAL TAR ENAMEl
SAW COAL TAR ENAMEL
SAW COAl TAR ENAMEl(OR EPO)(Y)
SMS COAl TAR ENAMEl
SMlS COAl TAR ENAMEl
SAW FUSIO N BONDED EPOXY
SAW COAl TAR ENAMEL
£RW·Hf COA l TAR ENAMEl
FW COAl TAR ENAMEL
SMl.S COAl TAR ENAMEl
FW COAl TAR ENAMEL
ERW-HF COAl TAR (NAMEl
FW COAl TAR ENAMEl
FW COAl TAR ENAMEl
FW COAl TAR ENAMEl
FW COAl TAR ENAMEl
SAW COAl TAR ENAMEl
SAW COAL TAR ENAMEl
SAW COAl TAR ENAMEl
SM.S COAl TAR E NAMEl
fW COAL TAR E NAMEl
FW COAL TAR ENAMEL
SAW COAL TAR ENAMEL
Dote
1981
1981
1969
19'il
1958
1958
1958
1958
1981
1967
1964
19'i3
1958
1958
1981
19'il
19'il
19'il
1953
1968
1968
1968
1958
19'il
1951
1970
Up stre: em/
Downstre.m
(ml)
U/U
U/U
3.1/1.1
~4/L7
U/U
U/U
U/U
13/~2
U/U
U/7.5
3.6/3.3
4.1/3.4
18/~1
l7/~4
W/U
7.7/0.3
a4/0.t
28/~
U/~
U/U
a3/0.t
H/H
U/U
U/U
U/U
~2/~1
Compreuor
Station
Spadn1 (ml)
36.4
364
39.3
36.4
36.4
36.4
39.3
39.3
39.3
35.5
39.5
39.5
39.3
35.5
37.3
81.6
81.6
81.6
81.6
81.6
81.6
81.6
38.4
39.3
37
70.4
MAOP
Establishe d
per192.619
(al(l)
(al( l )
(al(3)
(al(3)
(al(3)
(al(3)
(al(3)
(a)(!)
(a)( I)
(a)(3)
(a)(3)
(a)(3)
(a)(3)
1•)(3)
(a)(!)
(a)( I)
(a)( I)
(a)(!)
(a)(3)
(a)( I)
(a)( I)
(a)(!)
(a)(3)
(c)
(a )(3)
(a)(3)
Special Permit Docket: PHMSA-2016-0006
OPID 18516
M llteri•l/
Ae rtaJ Phototraphv Pressure Test Oocumenu
Se1ment ln-Une
~ak/ SCC/SSWC (w/1 20
Prenwe T u ted lnspecte
ml of 54Jment) aft .. (to badlup
d
MPS onlyor
MPS re cord
'test')
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
2012
y / Y
y / Y
y /Y
y /Y
Y/Y
Y/Y
y /Y
y /Y
y /Y
Y/Y
Y/MP5
Y/Y
y /Y
y /Y
y / Y
y /Y
Y/Y
y /Y
y /Y
y /Y
y /Y
y /Y
y /Y
Y / MPS
y /Y
y / Y
~ak/SCC/SSW C
N/A
N/A
leak ( 1/23/2007)
N/A
NO
N/A
N/A
N/A
N/A
N/A
N/A
lea< (6/6/1986)
leak (11/6/1987)
NIP
NO
N/A
N/A
lea< (3/4/1995)
lea k (3/4/1995)
lea< ( 10/1011969)
lea< (3/23/1965)
sccl
scc1
N/ A
NO
NO
NO
YES
YES
YES
sec'
Leak (8/31/1983) J SCC1
lea< (8/31/1983)
leak ( 1/23/2007)
sed
YES
NO / NO
NlP
NO
NSlP
m
m
m
m
m
m
m
m
m
m
m
m
m
m
m
m
m
m
m
m
m
m
m
m
m
m
N/ A
N/A
N/ A
N/A
N/ A
N/ A
N/A
N/A
N/A
N/ A
YES
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/ A
N/A
N/A
N/A
N/A
YES
N/A
N/A
Special Permit: PHMSA-2016-0006- Southern Natural Gas Company
Page 27 of27

<<<PAGE 1>>>

U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
Special Permit Analysis and Findings
Special Permit Information:
Docket Number:
Requested By:
Operator ID#:
Date Requested:
Code Section(s):
PHMSA-20 16-0006
Southern Natural Gas Company, L.L.C.
18516
January 11 , 201 6
49 CFR §§ l92.611(a) and (d), 192.61 9(a), and 192.5
Purpose:
The Pipeline and Hazardous Materials Safety Administration (PHMSA) provides this
information to describe the facts of the subject special permit application submitted by Southern
Natural Gas Company, L.L.C.1 (SNG), to discuss any relevant public comments received with
respect to the application, to present the engineering/safety analysis of the special penn it
application, and to make findings regarding whether the requested special permit should be
granted and if so under what conditions. SNG requests that PHMSA waive compliance from 49
Code of Federal Regulations (CFR) §§ 192.611 (a) and (d), 192.619(a), and 192.5 for 26
segments and 5.90 miles of natural gas transmission pipeline segments as described in Appendix
A ?
Pipeline System Affected:
This special permit request applies to 26 segments and 5.90 miles of natural gas transmission
pipeline operated by SNG and located in the states of Alabama, Georgia, Louisiana, and
Mississippi where a change has occurred from an original Class l location to a Class 3 location.
1 Southem Natural Gas Company, L.L.C. is owned by Kinder Morgan, Inc.
2 Appendix A of this special permit lists the pipeline special permit segment location (County and State), MAOP,
class location, diameter, wall thickness, grade, seam type, boundaries, and other attributes. Appendix A can be
reviewed on Docket PHMSA-20 1 6-0006 at www.regulations.gov.
Page 1 of 11
Special Permit Analysis
PHMSA-2016-0006- Southern Natural Gas Company, L.L.C. and Findings

<<<PAGE 2>>>

This special permit allows SNG to continue to operate the 26 pipeline segments and 5.90 miles at
their current maximum allowable operating pressure (MAOP).
Special Permit Request:
SNG submitted an application to PHMSA on January 11 , 2016, for a special permit seeking
relief from the Federal pipeline safety regulations in §§ 192.611 (a) and (d), 192.6 19(a), and
192.5 for 26 segments and 5.90 miles of natural gas transmission pipeline as described in
Appendix A of the Special Permit Conditions. The special permit segments are located in the
states of Alabama, Georgia, Louisiana, and Mississippi.
This special permit applies to the special permit segments listed in Appendix A. Special permit
segments shall be divided into two (2) categories: Type A special permit segments and Type B
special permit segments.
• Type A special permit segments include those special permit segments where there is a
cluster, as described in 49 CFR § 192.5(c), ofmore than 10 buildings intended for human
occupancy in a "class location unit" and for which the MAOP has not been confi1med in
accordance with 49 CFR § 192.611 (a). Type A special permit segments must be replaced
or pressure tested so that the MAOP is commensurate with the present class location
within three (3) years of issuance of this special permit. There are 1.54 miles of Type A
special permit segments and of this total 1.50 miles must be replaced and 0.04 miles
must be pressure tested as listed on Attachment A.
• Type A special permit segments with pipe with integrity issues as determined by
Conditions 6(c) and 14 or that have not been pressure tested in accordance with 49 CFR
Part 192, Subpart J to 1.25 times MAOP of this special permit must be replaced within
two and one-half (2 Yl) years of the grant of this special permit or within two (2) years of
assessment finding.
• Type B special permit segments include those special permit segments where there is a
cluster, as described in 49 CFR § 192.5(c), of 10 or fewer buildings intended for human
occupancy in a "class location unit" and for which the MAOP has not been confirmed in
accordance with 49 CFR § 192.6 11 . There are 4.36 miles of Type B special permit
segments and 0.72 miles of this total must be pressure tested as listed on Attachment A.
Page 2 of 11
Special Permit Analysis
PHMSA-2016-0006- Southern Natural Gas Company, L.L.C. and Findings

<<<PAGE 3>>>

3
• Special permit inspection area
- is defined as a one ( l) mile continuous segment on
both sides of the special permit segment (Type A and Type B) plus the footage in the
special permit segment. Appendix A lists the boundaries for the special permit
inspection area associated with each special permit segment. The special permit
inspection areas total 57.90 miles of pipe as detailed in Attachment A.
Subsequent to the issuance of this special permit, those special permit segments that have been
pressure tested or replaced such that the MAOP has been made commensurate with the present
class location as defined in 49 CFR § 192.611 would no longer be included in this special permit.
This special permit allows SNG to continue to operate the pipeline segments at their current
maximum allowable operating pressure (MAOP) until either replaced, hydrostatically tested, or
operated in accordance with the special permit conditions. The Federal pipeline safety
regulations in 49 CFR § 192.611 (a) require natural gas pipeline operators to confirm or revise the
MAOP of a pipeline segment after a change in class location. A special permit would allow
SNG to continue to operate each of the 26 segments and 5.90 miles at their existing MAOP's
despite a change in class location for the special permit specified time interval.
Public Notice:
On February 23,2016, PHMSA posted a notice of this special permit request in the Federal
Register (8 1 FR 9075). PHMSA received two (2) public comment letters in response to the draft
EA from a public person concerning a pipeline crossing of the St. Clair River in Michigan and
from the "Pipeline Safety Trust" dated March 24, 20 16, concerning this proposed special permit.
The public comments are summarized as noted below and the referenced Findings ofNo
Significant Impact (FONSI) can be reviewed on the docket (PHMSA-20 16-0006) at
vvvvvv.regulations.gov.
• A summary of the questions asked by Pipeline Safety Trust are below:
3 Special permit inspection areas throughout these conditions include special permit segments unless specifically
defined as not appl icable or if the special permit segment has more stringent conditions.
Page 3 of 11
Special Permit Analysis
PHMSA-2016-0006- Southern Natural Gas Company, L.L.C.
and Findings

<<<PAGE 4>>>

•
Only PHMSA announcement of the permit noted the fact that the operator's
previous class locations had been in error. (FONSI Review: Section II)
•
The 5-year waiver to accomplish this seems unreasonably long. (FONSI Review:
Section II, Footnote 2)
•
The Pipeline Safety Trust had several concerns with the information presented in
the application and the environmental assessment.
• Claimed environmental and safety benefit of the permit would occur from
the elimination of the methane emissions from pipeline blowdowns;
(FONSI Review: Section Vlll)
• Application fails in a couple of cases to provide a complete comparison of
the effects of granting or denying the permit including the impact on
adjacent right-of-way owners by allowing the existing pipe to remain in-
service; (FONSI Review: Section V)
• In the section of Safety Risks the operator indicates that the consequence
of a failure would be no different if the permit is granted or is denied,
without an indication of whether denying the permit would result in a
reduction of pressure or pipe replacement; ( FONSI Review: Section V)
• There appears to be many segments included in the application which have never
been tested in that their MAOP was determined by the Grandfather Clause
(§ 192.619(c)). (FONSI Review: The special permit conditions would require as a
minimum pressure tests for any segments that had not been pressure tested.)
• The application fails to give a complete useful response to § 190.34l(c)(4).
(FONSI Review: Section II)
• Rather than use the special permit process in a situation like this, PHMSA should
consider entering a consent agreement with the operator with both acknowledging
the operator is out of compliance. PHMSA risks regulating many individual
operators by special permit, without any justification for why the regulations
should not be met, in effect negating the safety factors in place under § 192.6 11 or
other regulations. (FONSI Review: Section II on pages 3 and 4 of 26 of the
FONSI notes as follows: "PHMSA considered both a Consent Agreement and
Page 4 of 11
Special Permit Analysis
PHMSA-2016-0006- Southern Natural Gas Company, L.L.C.
and Findings

<<<PAGE 5>>>

Safety Order in reviewing the issues of the SNG request. Since the operator
notified PHMSA of the violation, PHMSA considered a special permit with
integrity management concepts in a special permit with conditions an appropriate
mechanism for this situation to maintain safety. Also, the special permit
conditions would ensure the special permit segments were maintained while the
segments could be upgraded with pipe replacements or pressure tests. With
integrity management procedures being effective in other safety situations,
PHMSA considers this to be an effective approach for the sliding mile areas with
10 or fewer dwellings or structures for human occupancy, which is the case for
over 92 percent (24 of26 segments) of the SNG 26 special permit segments.
Special permit conditions are measures to assess, evaluate, and implement
measures to manage and eliminate threats to pipe integrity and public safety in
areas of high consequence such as these sliding mile special permit segments."
The special permit requires replacement or pressure testing of segments with over
10 dwelling. The special permit has conditions and integrity management
procedures for the special permit inspection area, 57.90 miles of pipeline.)
The request letter, Federal Register notice, public comments, FONSI, and all other pertinent
documents are available for review in Docket No. PHMSA-20 16-0006 in the Federal Docket
Management System (FDMS) located on the internet at www.Regulations.gov.
Analysis:
Background: On June 29, 2004, PHMSA published in the Federal Register (69 FR 38948) the
criteria it uses for the consideration of class location change waivers, now being granted through
special permits. First, certain threshold requirements must be met for a pipeline section to be
further evaluated for a class location change special permit. Second, the age and manufacturing
process of the pipe; system design and construction; environmental, operating and maintenance
histories; and integrity management program elements are evaluated as significant criteria.
These significant criteria are presented in matrix form and can be reviewed in the FDMS, Docket
Number PHMSA- RSPA-2004-1740 I. Third, such special permits will only then be granted
Page 5 of 11
Special Permit Analysis
PHMSA-2016-0006- Southern Natural Gas Company, L.L.C.
and Findings

<<<PAGE 6>>>

when pipe conditions and the operator's integrity management program provides a level of safety
equal to a pipe replacement or pressure reduction.
Threshold Requirements: Each ofthe threshold requirements published by PHMSA in the
June 29, 2004, Federal Register notice is discussed below in regards to the SNG special permit
petition.
1) No pipeline segments in a class location changing to Class 4 location will be considered.
This special permit request is for 26 segments and 5.90 miles on the SNG pipeline system
where a class location change has occurred from Class 1 to Class 3 locations as defined in
§ 192.5(c) for cluster locations and segments outside the cluster (and inside the sliding mile
for the class location) where an additional dwelling(s) have been identified. SNG has met
this requirement.
2) No bare pipe will be considered. These SNG special permit segments are coated with an
external protective coating. SNG has met this requirement.
3) No pipe containing wrinkle bends will be considered. There are no wrinkle bends in the
special permit segments. SNG has met this requirement.
4) No pipe segments operating above 72% of the specified minimum yield strength (SMYS)
will be considered for a Class 3 special permit. The special permit segments operate at or
below 72% SMYS. SNG has met this requirement.
5) Records must be produced that show a hydrostatic test to at least 1.25 x maximum allowable
operating pressure (MAOP). SNG will pressure test any segments that do not meet this
requirement through the special permit conditions.
6) In-line inspection (ILl) must have been performed with no significant anomalies identified
that indicate systemic problems. SNG will meet this requirement through the special permit
conditions.
7) Criteria for consideration of class location change waiver, now being granted through special
permits, published by PHMSA in the Federal Register (69 FR 38948), define a · waiver
inspection area (5pecial permit inspection area) as up to 25 miles of pipe either side of the
waiver segment (special permit segment). The 5pecial permit inspection area must be
inspected according to SNG's integrity management program and periodically inspected with
Page 6 of 11
Special Permit Analysis
PHMSA-2016-0006- Southern Natural Gas Company, L.L.C.
and Findings

<<<PAGE 7>>>

an in-line inspection technique. The special permit inspection area extends one-mile out
from either side of the special permit segments and the Class location 3 sliding mile. This
additional length was used since the Type B areas that are not being replaced are locations
with 10 or fewer buildings intended for human occupancy in a "class location unit" and are
outside the original "cluster area." This special permit is contingent upon SNG's
incorporation of each of the special permit segments in its written integrity management
program as a ··covered segment " in a "high consequence area., (HCA) per 49
CFR § 192.903.
Criteria Matrix: The original and supplemental data submitted by SNG for the special permit
segment have been compared to the class location change special permit criteria matrix. The
special permit segments fall in the probable acceptance column of the criteria matrix for all
criteria except for:
• Possible acceptance - pipe manufacture, pipe material, pipe coating, and several leaks
within 20-miles of the special perm if segment.
The data findings below fall within the "probable and possible acceptance" columns of the
criteria matrix:
1) Pipe design and construction, including pipe manufacture, material and design stress:
• SNG pipeline special permit segments have:
o Pipe manufactured with the following pipe seams: high-frequency electric
resistance welded, flash welded, double submerged arc welded, seamless, Helical
submerged arc weld (spiral pipe), and submerged arc weld.
o Pipe coatings included: coal tar enamel and fusion bonded epoxy.
o Pipe design stress was 72% specified minimum yield strength or lower.
o Several leaks within 20-miles of the special permit segment: SNG will be
required to conduct a stress corrosion cracking assessment (SCCDA) of the
special permit segments to evaluate where the risk of stress corrosion cracking
Page 7 of 11
Special Permit Analysis
PHMSA-2016-0006- Southern Natural Gas Company, L.L.C.
and Findings

<<<PAGE 8>>>

(SCC) is present. SNG will be required to implement a plan to improve cathodic
protection reliability and perform inspections for sec during excavations.
• To further address pipe manufacturing, material, construction, pipe coating, SCCDA,
and possible pipe leak issues, this special permit will include conditions requiring SNG to
treat all special permit segments as "covered segments" in an HCA per 49 CFR
§ 192.903.
• SNG will also be required to perform ILl assessments, anomaly repairs, close interval
surveys, identify any pipeline segment that may be susceptible to pipe seam issues
because of the vintage of the pipe, the manufacturing process of the pipe, or other issues
and stress corrosion cracking direct assessment (SCCDA) along the entire length of the
special permit inspection areas and special permit segments according to the
requirements of 49 CFR § 192.929 after the grant of this special permit.
• This special permit will include a condition that SNG must continue to operate each
special permit segment at or below its existing MAOP.
PHMSA has determined that imposing the special permit conditions will address these concerns
and provide equi valent safety for these areas.
Operational Integrity Compliance: PHMSA has reviewed this special permit request to ensure
that integrity threats to the pipeline in the special permit segments and special permit inspection
areas are addressed in the operator' s operations and management plan (O&M Plan). SNG must
have a systematic program to review and remediate pipeline safety concerns. Additional
operational integrity review and remediation requirements will be required by this special permit
for this special permit segment class location change. The pipeline operational integrity
requirements are to ensure that the operator has an ongoing program to locate and remediate
safety threats. Some of these threats to integrity and safety are the pipe coating quality, cathodic
protection effectiveness, anomalies in the pipe steel, and material and structures either along or
near the pipeline that could cause the cathodic protection system to be ineffective. PHMSA
carefully designed a comprehensive set of conditions that SNG would be required to meet in
order for the special permit to be granted. Among other things, the conditions include:
Page 8 of 11
Special Permit Analysis
PHMSA-2016-0006 - Southern Natural Gas Company, L.L.C.
and Findings

<<<PAGE 9>>>

1) Special permit inspection areas must be incorporated into its SNG's written integrity
management program (IMP) as a ''covered segment " in a "high consequence area
(HCA)" in accordance with 49 CFR § 192.903.
2) A close interval survey to determine the effectiveness of the cathodic protection system
must be performed within the special permit segments and special permit inspection area
and all areas with inadequate cathodic protection must be remediated. Close interval
surveys must be perf ormed on a seven (7) year reassessment interval.
3) Cathodic protection reliability and inspections for stress corrosion cracking (SCC) must
be performed.
4) Stress corrosion cracking surveys on the pipeline will be required to ensure that the pipe
steel is not cracking due to the effects of high and near neutral pH SCC within the special
permit segments and special permit inspection area.
5) Operations and maintenance (O&M) manual(s) must include the conditions of the special
permit including in-line inspection (ILl), close interval inspections (CIS), remediation,
and reassessment intervals.
6) Annual reports must be sent by SNG to PHMSA updating compliance.
7) Interference currents from electric transmission lines and other interfering structures in
the special permit segments and special permit inspection area must be identified,
controlled and mitigated by conducting surveys and installing remediation measures
where required.
8) Anomalies and dents on the pipeline must be repaired based upon the special permit
repair criteria for the special permit segments and special permit inspection areas.
9) Pipeline longitudinal seams within the special permit segments and special permit
inspection areas must have an engineering analysis to determine if there are any threats
and remediated if integrity threats are determined.
I 0) Data integration of special permit condition findings and remediation must be maintained
for the special permit segments and special permit inspection areas.
Page 9 of 11
Special Permit Analysis
PHMSA-2016-0006- Southern Natural Gas Company, L.L.C.
and Findings

<<<PAGE 10>>>

11) Long term pipeline system flow reversals that include a special permit segment must
have a written plan that corresponds to those applicable criteria identified in PHMSA
Advisory Bulletin (ADB-2014-04),
"Guidance for Pipeline Flow Reversals, Product
Changes and Conversion of Service" issued on September 18, 2014 (79 FR 56121 ,
Docket PHMSA-20 14-0400).
12) A senior executive officer, vice president or higher must certify in writing that SNG is
complying with the special permit conditions.
The special permit will contain numerous conditions to ensure SNG meets or exceeds the
threshold requirements with equivalent safety and to ensure that granting the special permit will
not be inconsistent with safety.
Past Enforcement History - 2005 through Mach 28. 2016
The enforcement history is an important reflection of how SNG has been observed to follow
pipeline safety regulations and is a major area of focus for the review of this application.
Below is a listing of PHMSA closed enforcement matters of all types in all PHMSA Regions for
SNG (OPID # 18516) from 2005 through March 28, 2016:
• Letters - of Concern or Warning - 3 matters
• Notices- of Amendment or of Probable Violation- 3 matters
• Orders - Corrective Action- 4 matters
• Orders - Safety - 0 matter
• Fines - $72,900 - 1 00% collected
• SNG had no repeat offences during this period.
PHMSA has determined that imposing the special permit conditions summarized in this
document will ensure that granting the special permit will not be inconsistent with safety.
Findings:
Based on the information submitted by SNG and PHMSA's analysis of technical, operational
and safety issues, and given the conditions that will be imposed in the special permit, PHMSA
Page 10 of 11
Special Permit Analysis
PHMSA-2016-0006- Southern Natural Gas Company, L.L.C.
and Findings

<<<PAGE 11>>>

finds that granting this special permit to SNG to operate special permit segments at the current
MAOP, where a change in class location has occurred from an original Class 1 location to a
Class 3 location, would not be inconsistent with pipeline safety.
Completed in Washington DC on: September 1, 2016
Prepared By: PHMSA- Engineering and Research Division
Page 11 of 11
Special Permit Analysis
PHMSA-2016-0006- Southern Natural Gas Company, L.L.C. and Findings

<<<PAGE 1>>>

U.S. Department
of Transportation
Pipeline and Hazardous
Materials Safety
Administration
1200 New Jersey Avenue, SE
Washington, D C. 20590
September I, 20 16
Mr. Gary Buchler
Chief Operating Officer
Kinder Morgan Natural Gas Division
Southern Natural Gas Company. L.L.C.
I 001 Louisiana Street. Suite 1000
Houston. Texas 77002
Docket No. PHMSA-2016-0006
Dear Mr. Buchler:
On January II , 20 16. Southern Natural Gas Company. L.L.C. (SNG) wrote to the Pipe line and
Hazardous Materials Safety Administration (PHMSA) requesting a spec ial permit to waive
compliance from PHMSA 's pipeline s· afety regulation in 49 CFR ~§ 192.6 11 (a) and (d).
192.6 19(a). and 192.5 for pipeline segments where the class location of the segment had been
changed in accordance with § 192.5(c). cluster rule. The regulation requires confirmation or
revision of the maximum allowable operating pressure (MAOP) o f a pipeline segment where the
class location has changed.
The special permit request is for 26 segments and 5.90 miles of the SNG natural gas transmission
pipeline system located in the states of Alabama. Georg ia. Louisiana. and Mississippi. The
pipeline segme nts are generall y short in length. not continuous. and are located in multiple states
and counties/parishes within those states. The regulatory relief from 49 CFR §§ 192.6 1 I.
192.61 9 and 192.5 through a special permit would include additional time (3-years) to either
replace or pressure test the pipe line segments in the class location sl iding mile and outside the
cluster area. where there are over 10 dwellings for human occupancy. Pipeline segments w ith \0
or fewer dwellings for human occupancy outside the cluster area. but w ithin the sliding mile.
would not be replaced and SNG would be required by the special permit conditions to imple ment
procedures to maintain pipeline safety by identifying. assessing. and remediating integrity threats
to the pipeline segments.
PHMSA is granting this special permit (enclosed). which w ill allow SNG to continue to operate
segments o f the SNG pipeline at their current MAOPs by implementing integrit y management
practices as de fined in the special permit conditions until the pipe is replaced. pressure tested. or
remediated. This special permit provides relie f from the Federal pipeline safe ty regulations fo r

<<<PAGE 2>>>

the SNG special permit segments and requires SNG to comply with certain condit ions and
limitations des igned to maintain pipeline safety.
PHMSA grants this special permit based on the findings set forth in the ''Special Permit Analysis
and Findings" document. which can be read in its entirety in Docket No. PHMSA-20 16-0006 in
the Federal Docket Management System (FDMS) located on the internet at
www.Regulati ons.gov.
My staff would be pleased to discuss this matter or any other regulatory matter with you.
Mr. John Gale. Director of Standards and Rulemak ing Division may be contacted at
202-366-0434. on regulatory matters and Mr. Kenneth Lee. Director of Engineering and
Research Division, may be contacted at 202-366-2694. on technical matters specific to this
special permit application
Sincerely,
Acting Associate Administrator
for Pipeline Safety
Enclosure: Special Permit - PHMSA-20 16-0006
PHMSA·2016-0006- Southern Natural Gas Company, L.L.C. Page 2 of 2
Letter of Decision

## Provenance

- Official: Yes
- Source: <https://www.regulations.gov/docket/PHMSA-2016-0006>
- Source ID: `phmsa-special-permits`
- SHA-256: `d8b51c262ac728c10b772ac91a8919c3558b3f6ca00e6dabd17470fda0c54ff6`
- Retrieved: 2026-08-20T01:06:17.853Z
- Exported: 2026-08-25T04:29:17.885Z
- Document slug: `phmsa-special-permit-phmsa-2016-0006`

### Source metadata

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  "renewal": "Mar 17, 2023",
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}
```