# TENNESSEE GAS PIPELINE COMPANY — Notice of Probable Violation

- **operation:** document
- **citation:** CPF 420081008
- **title:** TENNESSEE GAS PIPELINE COMPANY — Notice of Probable Violation
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2008-05-19
- **effective on:** Not available
- **summary:** CLOSED notice of probable violation citing 192.163(d), 192.179(b)(1), 192.317(b), 192.475(a), 192.475(b), 192.481(a), 192.706(a), 192.745(a).
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- **markdown:** https://regulus.evalyn.ai/document/phmsa-enforcement-420081008.md
- **app url:** https://regulus.evalyn.ai/document/phmsa-enforcement-420081008
- **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/420081008
**body:**

Notice of Probable Violation involving TENNESSEE GAS PIPELINE COMPANY. PHMSA's enforcement data identifies the cited regulations as 192.163(d),  192.179(b)(1),  192.317(b),  192.475(a),  192.475(b),  192.481(a),  192.706(a),  192.745(a). The case was opened on 2008-05-19 and is reported as closed as of 2014-11-19. Proposed civil penalty: $28,000. Assessed civil penalty: $19,000. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

420081008_Closure_11192014.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420081008/420081008_Closure_11192014.pdf

420081008_Closure_11192014_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420081008/420081008_Closure_11192014_text.pdf

420081008_Final Order_10282013.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420081008/420081008_Final%20Order_10282013.pdf

420081008_Final Order_10282013_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420081008/420081008_Final%20Order_10282013_text.pdf

420081008_NOPV PCP PCO_05192008.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420081008/420081008_NOPV%20PCP%20PCO_05192008.pdf

420081008_NOPV PCP PCO_05192008_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420081008/420081008_NOPV%20PCP%20PCO_05192008_text.pdf

420081008_Operator_Response_and_Request_for_Hearing__06262008.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420081008/420081008_Operator_Response_and_Request_for_Hearing__06262008.pdf

420081008_NOPV PCP PCO_05192008_text.pdf

NOTICE OF PROBABLE VIOLATION
PROPOSED CIVIL PENALTY
and
PROPOSED COMPLIANCE ORDER
CERTIFIED MAIL - RETURN RECEIPT REQUESTED
May 19, 2008
Mr. Bill Cope
Vice President Eastern Operations
Tennessee Gas Pipeline Co
PO Box 2563
Birmingham AL 35202
CPF 4-2008-1008
Dear Mr.Cope:
During January, February, March, April, May, September and October 2006, representatives of
the Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601
of 49 United States Code inspected your Tennessee Gas Pipeline facilities and records in
Texas and Louisiana.
As a result of the inspection, it appears that you have committed probable violations of the
Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and
the probable violation(s) are:
1. §192.163 Compressor stations: Design and construction.
(d) Fenced areas. Each fence around a compressor station must have at least
two gates located so as to provide a convenient opportunity for escape to a place
of safety, or have other facilities affording a similarly convenient exit from the
area. Each gate located within 200 feet (61 meters) of any compressor plant
building must open outward and, when occupied, must be openable from the
inside without a key.
It was observed during the field portion of the inspection that Alamo compressor station had a
locked personnel gate approximately 50’ west of the compressor. The operator later supplied
PHMSA with pictures showing that a crash bar was installed on this gate.



2. §192.179 Transmission line valves.
(b) Each sectionalizing block valve on a transmission line, other than offshore
segments, must comply with the following:
(1) The valve and the operating device to open or close the valve must be
readily accessible and protected from tampering and damage.
During the inspection it was observed that, a 16" block valve [507G-106] and a 24" valve [512-1]
at Hwy 332 and valve 404 were not protected against damage and were accessible to vehicular
traffic. Inadequate protection from damage was also observed at some other valve locations:
Lirette on line 523R100 were only enclosed by a 4 foot high fence; Fences were unlocked and
downed (due to Katrina) at the Mississippi River crossing.
Also during the inspection it was observed that valves were not protected from tampering. The
operator installs locks on its valves to prevent tampering but these locks were not present at
some locations: valves at Lirette on line 523R100; valves at LaRose, Delta Duck and Mississippi
River crossing.
3. §192.317 Protection from hazards.
(b) Each above ground transmission line or main, not located offshore or in
inland navigable water areas, must be protected from accidental damage by
vehicular traffic or other similar causes, either by being placed at a safe distance
from the traffic or by installing barricades.
Tennessee Gas is not protecting their pipeline from accidental damage where lateral 14D-100
takes off from line 1 and line 2. During the inspection it was observed that there was evidence
of the above ground piping being struck by agricultural equipment.
4. §192.475 Internal corrosion control: General
(b) Whenever any pipe is removed from a pipeline for any reason, the internal
surface must be inspected for evidence of corrosion. If internal corrosion is
found-
(1) The adjacent pipe must be investigated to determine the extent of internal
corrosion:
(2) (3) Replacement must be made to the extent required by the applicable
paragraphs of §192.485, §192.487, or§ 192,489; and,
Steps must be taken to minimize the internal corrosion.
During the inspection it was identified that two 4 inch hot taps were installed on July 14-22, 2005
on Morales line. As a part of this activity hot tap coupons were removed. Records were
requested during the inspection but Tennessee Gas Pipeline did not provide a record of an
internal inspection as required by 192.475 (b).
5. §192.475 Internal corrosion control: General
2



(a) Corrosive gas may not be transported by pipeline, unless the corrosive effect
of the gas on the pipeline has been investigated and steps have been taken to
minimize internal corrosion.
§192.477 Internal corrosion control: Monitoring.
If corrosive gas is being transported, coupons or other suitable means must be
used to determine the effectiveness of the steps taken to minimize internal
corrosion. Each coupon or other means of monitoring internal corrosion must be
checked two times each calendar year, but with interval not exceeding 7 1/2
months.
As part of TGP’s overall corrosion control program, they install internal corrosion monitoring
coupons to evaluate the corrosive effect of their product. TGP’s procedures specify that they
install coupons for short periods of time (usually 1 month) and then the coupons are evaluated.
Specific response and remediation actions are established depending on the condition of the
coupon. Per §192.477 and accepted industry standards these coupons should remain in the
gas stream continuously, then removed and evaluated two times per year. TGP’s conduct and
written procedures do not follow the prescriptive requirement of these regulations.
At TGP’s Kinder station the internal corrosion monitoring coupon [S4504] was installed on
12/14/04 and removed on 01/19/05. Records provided during the inspection and TGP’s
procedures require (based on the condition of the coupon) that TGP “re-evaluate immediately”.
A replacement monitoring coupon [S5340] was not installed at that location until 01/20/06. TGP
did not comply with applicable requirements and could not demonstrate that it followed its own
procedures.
During the inspection it was observed that TGP’s coupons used to investigate internal corrosion
are not always placed in effective locations. It is unlikely that installations such as can be found
on platform Ship Shoal 167A (where the coupon is held off to the side of a vertical riser) will be
able to provide meaningful results. The coupons should be placed such that they are near the
area where corrosive constituents accumulate most (bottom of the pipe).
6. §192.481 Atmospheric corrosion control: Monitoring.
(a) Each operator must inspect each pipeline or portion of pipeline that is
exposed to the atmosphere for evidence of atmospheric corrosion, as follows:
If the pipeline is located:
Onshore
Offshore
Then the frequency of inspection is:
At least once every 3 calendar years, but with
intervals not exceeding 39 months.
At least once each calendar year, but with
intervals not exceeding 15 months.
The Tennessee Gas Pipeline/Nautilus interchange was installed January 2002. Tennessee
Gas could not provide documentation at the inspection to demonstrate that subsequent
atmospheric corrosion control monitoring and inspection had occurred.
3



7. 8. §192.706 Transmission lines: Leakage surveys.
Leakage surveys of a transmission line must be conducted at intervals not
exceeding 15 months, but at least once each calendar year. However, in the case
of a transmission line which transports gas in conformity with §192.625 without an
odor or odorant, leakage surveys using leak detector equipment must be
conducted-
(a) In Class 3 locations, at intervals not exceeding 7 1/2 months, but at least twice
each calendar year; and
(b) In Class 4 locations, at intervals not exceeding 4 1/2 months, but at least four
times each calendar year.
Tennessee Gas class 3 leak survey on lines 409A - 101 and 409A - 102 exceeded 7.5 months
in 2005. The survey was conducted on March 8, 2005 and not again until November 9, 2005.
§192.745 Valve maintenance: Transmission lines.
(a) Each transmission line valve that might be required during any emergency
must be inspected and partially operated at intervals not exceeding 15 months,
but at least once each calendar year.
According to records reviewed during the inspection, valve maintenance on "El Banito." line
exceeded 15 months between January 26, 2004 to August 17, 2005.
Proposed Civil Penalty
Under 49 United States Code, § 60122, you are subject to a civil penalty not to exceed
$100,000 for each violation for each day the violation persists up to a maximum of $1,000,000
for any related series of violations. The Compliance Officer has reviewed the circumstances
and supporting documentation involved in the above probable violation(s) and has
recommended that you be preliminarily assessed a civil penalty of $28,000 as follows:
Item number PENALTY
5 $18,000
6 $10,000
Proposed Compliance Order
With respect to items 2, 3, 5 and 6 pursuant to 49 United States Code § 60118, the Pipeline and
Hazardous Materials Safety Administration proposes to issue a Compliance Order to
Tennessee Gas Pipeline. Please refer to the Proposed Compliance Order, which is enclosed
and made a part of this Notice.
We have reviewed the circumstances and supporting documents involved in this case,
pertaining to items 1, 4, 7 and 8 and have decided not to conduct additional enforcement action
or penalty assessment proceedings at this time. We advise you to correct the items identified in
this letter. Failure to do so will result in Tennessee Gas Pipeline being subject to additional
4



enforcement action.
Response to this Notice
Enclosed as part of this Notice is a document entitled Response Options for Pipeline Operators
in Compliance Proceedings. Please refer to this document and note the response options. Be
advised that all material you submit in response to this enforcement action is subject to being
made publicly available. If you believe that any portion of your responsive material qualifies for
confidential treatment under 5 U.S.C. 552(b), along with the complete original document you
must provide a second copy of the document with the portions you believe qualify for
confidential treatment redacted and an explanation of why you believe the redacted information
qualifies for confidential treatment under 5 U.S.C. 552(b). If you do not respond within 30 days
of receipt of this Notice, this constitutes a waiver of your right to contest the allegations in this
Notice and authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in
this Notice without further notice to you and to issue a Final Order.
In your correspondence on this matter, please refer to CPF 4-2008-1008 and for each document
you submit, please provide a copy in electronic format whenever possible.
Sincerely,
R. M. Seeley
Director, Southwest Region
Pipeline and Hazardous
Materials Safety Administration
Enclosures: Proposed Compliance Order
Response Options for Pipeline Operators in Compliance Proceedings
5



PROPOSED COMPLIANCE ORDER
Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety
Administration (PHMSA) proposes to issue to Tennessee Gas Pipeline Co (TGP) a Compliance
Order incorporating the following remedial requirements to ensure the compliance of Tennessee
Gas Pipeline Co with the pipeline safety regulations:
1. 2. 3. 4. 5. 6. In regard to Item Number 2 of the Notice, TGP should review their procedures
related to §192.179. TGP should survey their valve locations and install
adequate protection from tampering and damage.
In regard to Item Number 3 of the Notice, TGP should review their procedures
related to §192.317. TGP should take the necessary steps to ensure that their
facilities are protected from accidental damage.
In regard to item 5 of the Notice, TGP should review their procedures related to
use and evaluation of internal corrosion coupons and make necessary changes
to be in compliance.
In regard to Item Number 6 of the Notice, TGP should review their procedures
related to §192.481. TGP shall conduct the appropriate inspection and perform
any required remediation.
The operator should complete these items within 60 days after receipt of a Final
Order. Submit documentation to R. M. Seeley, Director, Southwest Region,
Pipeline and Hazardous Materials Safety Administration.
Tennessee Gas shall maintain documentation of the safety improvement costs
associated with fulfilling this Compliance Order and submit the total to R. M.
Seeley, Director, Southwest Region, Pipeline and Hazardous Materials Safety
Administration. Costs shall be reported in two categories: 1) total cost
associated with preparation/revision of plans, procedures, studies and analyses,
and 2) total cost associated with replacements, additions and other changes to
pipeline infrastructure.
6

420081008_Final Order_10282013_text.pdf

OCTOBER 28, 2013
Mr. Norman G. Holmes
President
Tennessee Gas Pipeline Company, LLC
1001 Louisiana Street
Houston, Texas 77002
Re: CPF No. 4-2008-1008
Dear Mr. Holmes:
Enclosed please find the Final Order issued in the above-referenced case. It partially withdraws
one allegation of violation, makes findings of violation, assesses a civil penalty of $19,000, and
specifies actions that need to be taken by Tennessee Gas Pipeline Company, LLC, to comply
with the pipeline safety regulations.
This is also to acknowledge receipt of the $10,000 payment Tennessee Gas made by wire
transfer dated June 30, 2008. When the remaining $9,000 penalty amount is paid, and the terms
of the compliance order have been completed, as determined by the Director, Southwest Region,
this enforcement action will be closed. Service of the Final Order by certified mail is deemed
effective upon the date of mailing, or as otherwise provided under 49 C.F.R. § 190.5.
Thank you for your cooperation in this matter.
Sincerely,
Jeffrey D. Wiese
Associate Administrator
for Pipeline Safety
Enclosure
cc: Mr. Rod Seeley, Director, Southwest Region, OPS
David M. Waterson, Jr., Esq., Counsel for Tennessee Gas Pipeline Company, LLC,
1001 Louisiana Street, Houston, TX 77002
CERTIFIED MAIL – RETURN RECEIPT REQUESTED



U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, D.C. 20590
____________________________________
In the Matter of )
Tennessee Gas Pipeline Company, LLC, ) )
)
)
Respondent. )
___________________________________ )
CPF No. 4-2008-1008
FINAL ORDER
Between January and October 2006, pursuant to 49 U.S.C. § 60117, representatives of the
Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety
(OPS), conducted an on-site pipeline safety inspection of the facilities and records of Tennessee
Gas Pipeline Company, LLC (TGP or Respondent), in Texas and Louisiana.1 TGP operates the
Tennessee Gas Pipeline, which consists of approximately 14,000 miles of pipeline extending
from locations on the Gulf of Mexico to Canada.
2
As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to
Respondent, by letter dated May 19, 2008, a Notice of Probable Violation, Proposed Civil
Penalty, and Proposed Compliance Order (Notice). In accordance with 49 C.F.R. § 190.207, the
Notice proposed finding that TGP had committed three violations of 49 C.F.R. Part 192,
assessing a civil penalty of $28,000 for the alleged violations, and ordering Respondent to take
certain measures to correct the alleged violations. The Notice also proposed finding that
Respondent had committed certain other probable violations of 49 C.F.R. Part 192 and warning
TGP to take appropriate corrective action or be subject to future enforcement action.
TGP responded to the Notice by letter dated June 26, 2008 (Response), and contested the
allegations contained in Items 4 and 5. The company paid the proposed civil penalty of $10,000
for Item 6, as provided in 49 C.F.R. § 190.227. As for the proposed compliance order, the
company provided information concerning the corrective actions it had taken and planned to take
with respect to Items 2 and 3, but objected to the proposed compliance terms for Items 5 and 6.
Although TGP did not specifically request a hearing, the Southwest Region recommended that a
hearing be held. A hearing was subsequently held on November 13, 2008, in Houston, Texas,
with an attorney from the Office of Chief Counsel, PHMSA, presiding. At the hearing,
1 Tennessee Gas Pipeline Company, LLC, is a wholly-owned subsidiary of El Paso Corporation, which owns and
operates approximately 42,000 miles of interstate natural gas pipelines in the United States. See
http://www.elpaso.com/pipelines (last accessed November 6, 2011).
2 SEC Form 10-K, Tennessee Gas Pipeline Company, March 1, 2010.



2
Respondent was represented by counsel. After the hearing, TGP provided additional written
materials and a post-hearing statement for the record, by letter dated December 9, 2008
(Closing).
FINDINGS OF VIOLATION
Uncontested Items
In its Response and at the hearing, TGP did not contest the allegations in the Notice that it
violated 49 C.F.R. Part 192, as follows:
Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 192.179(b)(1), which states:
§ 192.179 Transmission line valves.
(a) . . . .
(b) Each sectionalizing block valve on a transmission line, other than
offshore segments, must comply with the following:
(1) The valve and the operating device to open or close the valve must
be readily accessible and protected from tampering and damage.
The Notice alleged that Respondent violated 49 C.F.R. § 192.179(b)(1) by failing to protect
several block valves from tampering and damage. Specifically, the Notice alleged that several
valves were either accessible to vehicular traffic, not adequately protected by fences, or left
unlocked. Respondent did not contest these allegations of violation. Accordingly, based upon a
review of all of the evidence, I find that Respondent violated 49 C.F.R. § 192.179(b)(1) by
failing to protect several block valves from tampering and damage.
Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 192.317(b), which states:
§ 192.317 Protection from hazards.
(a) . . . .
(b) Each aboveground transmission line or main, not located offshore
or in inland navigable water areas, must be protected from accidental
damage by vehicular traffic or other similar causes, either by being placed
at a safe distance from the traffic or by installing barricades.
The Notice alleged that Respondent violated 49 C.F.R. § 192.317(b) by failing to protect an
aboveground transmission line from accidental damage by vehicular damage or other similar
causes. Specifically, the Notice alleged that there was evidence that a section of an
aboveground transmission line had been struck by agricultural equipment. Respondent did not
contest this allegation of violation. Accordingly, based upon a review of all of the evidence, I
find that Respondent violated 49 C.F.R. § 192.317(b) by failing to protect an aboveground
transmission line from accidental damage by vehicular traffic or other similar causes.



3
Item 6: The Notice alleged that Respondent violated 49 C.F.R. § 192.481(a), which states:
§ 192.481 Atmospheric corrosion control: Monitoring.
(a) Each operator must inspect each pipeline or portion of pipeline
that is exposed to the atmosphere for evidence of atmospheric
corrosion, as follows:
If the pipeline is
located: Then the frequency of inspection is:
Onshore…….. At least once every 3 calendar years, but with
intervals not exceeding 39 months
Offshore…….. At least once each calendar year, but with intervals
not exceeding 15 months.
The Notice alleged that Respondent violated 49 C.F.R. § 192.481(a) by failing to inspect a
portion of pipeline exposed to the atmosphere for evidence of atmospheric corrosion at least once
every three calendar years, but with intervals not exceeding 39 months. Specifically, the Notice
alleged that TGP could not provide documentation that a pipeline interchange installed in
January 2002 had ever been inspected for atmospheric corrosion. Respondent did not contest
this allegation of violation. Accordingly, based upon a review of all of the evidence, I find that
Respondent violated 49 C.F.R. § 192.481(a) by failing to inspect a portion of pipeline for
atmospheric corrosion within the required intervals.
These findings of violation will be considered prior offenses in any subsequent enforcement
action taken against Respondent.
Contested Item
The Notice alleged that Respondent violated 49 C.F.R. Part 192, as follows:
Item 5: The Notice alleged that Respondent violated 49 C.F.R. §§ 192.475(a) and 192.477,
which state:
§ 192.475 Internal corrosion control: General.
(a) Corrosive gas may not be transported by pipeline, unless the
corrosive effect of the gas on the pipeline has been investigated and
steps have been taken to minimize internal corrosion.
§ 192.477 Internal corrosion control: Monitoring.
If corrosive gas is being transported, coupons or other suitable
means must be used to determine the effectiveness of the steps taken to
minimize internal corrosion. Each coupon or other means of
monitoring internal corrosion must be checked two times each
calendar year, but with intervals not exceeding 7½ months.



4
The Notice alleged that Respondent violated 49 C.F.R. §§ 192.475(a) and 192.477 by failing to
conduct its internal corrosion control monitoring program in a manner that effectively
determined that any internal corrosion was being minimized. Specifically, the Notice alleged
that TGP’s use of corrosion coupons in its internal corrosion control monitoring program was not
carried out in a manner that effectively monitored for corrosivity and that TGP did not always
place its corrosion coupons in locations where they would be effective. In particular, the Notice
cited the placement of Ship Shoal Coupon 167A as ineffective due to its location off to the side
of a vertical riser, as opposed to nearer the bottom of the pipe where any corrosive constituents
would be likely to accumulate. The Notice also alleged that TGP installed corrosion coupons for
short, discontinuous periods of time which did not meet the requirements of § 192.477 that
coupons be maintained in the gas stream and then removed and evaluated two times per year. In
particular, the Notice cited Coupon S4504 as being removed on January 19, 2005, but not
replaced until Coupon S5340 was installed at that location on January 20, 2006.
At the hearing and in its Response and Closing, TGP contested these allegations. TGP argued
broadly that it transported tariff quality gas, not corrosive gas, and that as a result it could not be
found in violation for the manner or effectiveness of its use of corrosion coupons since corrosion
control monitoring is only required for pipelines that transport corrosive gas.3 TGP also argued
that Ship Shoal Coupon 167A was placed in a location that is effective for determining the
corrosivity of a gas/liquid hydrocarbon (two phase) stream.4 TGP also contended that its use of
electron microscope (EM) coupons in a discontinuous manner was permissible under the
regulations because this type of coupon was intended to be used differently from standard
weight-loss coupons and that it considered them to be corrosion-detection coupons rather than
corrosion-monitoring coupons.
5 With respect to Coupon S4504, TGP explained that Hurricanes
Katrina and Rita impacted the timing of the installation of the next coupon.6
Federal gas pipeline safety regulations7 were promulgated under the Natural Gas Pipeline Safety
Act of 19688 to provide adequate protection against risks to life and property posed by pipeline
transportation and pipeline facilities.9 The corrosion control regulations,10 which include
§§ 192.475 and 192.477, were issued to ensure that gas pipeline operators identify and address
3 Closing at 2-6.
4 Response at 9.
5 Id. at 5-6. Weight-loss coupons, as the name implies, indicate corrosion rates by being weighed upon removal.
The difference between the original weight of the coupon and the weight when removed is recorded and compared
with the series of coupons in the same pipe location for multiple time periods of similar length. This allows an
operator to determine whether corrosion begins accelerating.
6 Id. at 7.
7 49 C.F.R. Part 192.
8 Pub. L. No. 90-481, 82 Stat. 720 (Aug. 12, 1968).
9 49 U.S.C. § 60102(a)(1) (2012).
10 49 C.F.R. pt. 192, subpt. I.



5
internal corrosion risks before they become pipeline failures. The regulations require pipeline
operators to monitor their pipelines for internal corrosion when the potential for corrosive effects
exists, and to take measures when necessary to ensure any such effects are minimized. Notably,
the regulations do not prescribe corrosion coupons as the only permissible means of conducting
corrosion control monitoring. If coupons are used, however, the regulations expressly require
that they be checked “two times each calendar year, but with intervals not exceeding
7½ months.”11
With respect to TGP’s argument that it transported tariff quality gas, not corrosive gas, and that
as a result it was not in violation of the cited regulations regardless of the manner or
effectiveness of its use of coupons, it should first be noted that previous PHMSA enforcement
cases have described the factors relevant to whether an operator should consider gas in a given
pipeline to be corrosive for purposes of making decisions about the need for corrosion control
monitoring. In the Consumers Energy case, I found that the presence of substances found in the
natural gas transported by U.S. pipelines such as carbon dioxide, hydrogen sulfide, and certain
microbes and bacteria, in the presence of water and condensates, can corrode the internal surface
of a pipeline. 12 In addition, certain pipe areas, such as low spots and locations where the gas
stream does not have sufficient velocity and/or turbulence to carry away condensates, may also
create environments conducive to internal corrosion and must be monitored.13
At the hearing and in its Closing, TGP argued that “tariff quality gas is dry gas under normal
operating conditions and is not corrosive.”14 TGP expressed the view that even when water or
liquids are introduced, “the potential for corrosion is minimal if the condition is temporary.”15
TGP further explained that liquid water can be removed through maintenance pigging and liquid
removal devices such as pipeline drips, or can be reabsorbed into the gas stream. TGP also
explained that its Subject Matter Experts (SMEs) take into account various factors such as gas
quality monitoring, liquid and soil sampling, on-site testing for water, and other factors in
determining whether to “develop a monitoring program…”.16
To the extent that TGP argued for the proposition that tariff quality gas transported by pipeline
need not be monitored for any potential corrosivity, I do not agree. As TGP itself acknowledged,
tariff quality gas, which can already have a moisture vapor content of seven pounds of water
vapor per million cubic feet of natural gas, can experience “short term upsets” during which
“liquid water or water vapor that could condense is introduced into the pipeline...”.17 The fact
11 49 C.F.R. § 192.477.
12 See In the Matter of Consumers Energy, Final Order, CPF No. 3-1999-1001. (Mar. 5, 2009) (available at
www.phmsa.dot.gov/pipeline/enforcement). See also In the Matter of BP Pipelines (North America), Inc., Final
Order, CPF No. 4-2007-5003. (July 19, 2010).
13 Id. at 2.
14 Closing at 2.
15 Id.
16 Id. at 6.
17 Id. at 3.



6
that liquid water can be removed through maintenance pigging or liquid removal devices such as
pipeline drips only underscores the fact that liquids susceptible to interacting with other
constituents in the gas can be present at times, even if not continuously or at all locations. More
to the point, this case does not present a scenario where an operator conducted a technical study
at the time its pipeline system was designed and began operating that provided a sound basis for
concluding that a corrosion coupon monitoring program was completely unnecessary. Here, the
pipeline designers or TGP itself decided long before the OPS inspection that a corrosion coupon
monitoring program was needed and installed corrosion-monitoring coupons on this pipeline
system.
18 Given that TGP (or its predecessors) originally made this judgment about the need for
a coupon monitoring program, OPS is acting within its regulatory authority in conducting
inspections to determine whether this coupon monitoring program is being conducted effectively.
With respect to the allegation in the Notice that TGP’s coupons were not always placed in
effective locations, OPS provided only one alleged example of a problematic location in the
Notice, that being Ship Shoal 167A. As described in detail at the hearing, TGP placed this
coupon in a sample chamber along a short section of vertical pipe that was downstream from
liquid re-injection and upstream from chemical inhibitor injection.19 TGP contended that this
location was “the most effective location on the platform to measure the corrosion potential of
the commingled liquid prior to chemical injection and that these conditions exist[ed] over only
4½ feet of piping which is all in the vertical position. . .”20
. OPS maintained that the coupon
needed to be located nearer the bottom of the pipe where any corrosive constituents would be
likely to accumulate.
As TGP correctly noted at the hearing, the corrosion control regulations do not require the “most
effective” coupon placement. Both parties did point out that TGP’s own written operating and
maintenance procedures require that “As a general rule, coupons should be placed in…the most
severe location with respect to corrosion.”21 However, while it could have done so, OPS did not
cite the regulation that requires an operator to follow its own written operating and maintenance
procedures and did not present evidence that TGP’s alleged coupon misplacement was
significant or systemic. Moreover, OPS was able to cite only a single example of alleged
inadequate coupon placement, which I find to be insufficient to support the general allegation
that TGP’s coupons were not always placed in effective locations. Accordingly, having
considered all of the information and arguments presented on this issue, I find that OPS did not
prove the allegation that TGP’s coupons were not placed in effective locations. The extent to
which this finding warrants a reduction in the penalty amount proposed in the Notice will be
addressed in the Assessment of Penalty section below.
With respect to the allegation that TGP’s corrosion monitoring coupons were not maintained in
the gas stream continuously and checked twice per calendar year, TGP argued at the hearing and
in its Response and Closing that its use of EM coupons in a discontinuous manner was
18 It appears that corrosion inhibitor was also determined necessary to be injected into the pipeline.
19 Hearing Presentation at 67-71.
20 Id.
21 Response at 8.



7
permissible under the regulations because this type of coupon was intended to be used differently
from standard weight-loss coupons and that it considered them to be corrosion-detection coupons
rather than corrosion-monitoring coupons.22
TGP stated that its electron microscope (EM) coupons were typically exposed for a 30 to 45 day
period and that additional exposure would actually render the readings unusable.23 TGP
contended that EM coupons offer some advantages over traditional weight-loss coupons in terms
of precision of measurement.24 OPS noted that section 5.2 of National Association of Corrosion
Engineers (NACE) RP0775-2005 industry standard states that “Continuous monitoring is
essential so that changes in the corrosion rate in a system may be detected as soon as possible
after they occur.” 25 This ensures that corrosivity is detected promptly, as opposed to being
detected by infrequent EM coupon monitoring only after it has potentially reached harmful
levels.
TGP is correct that the regulations do not expressly state that corrosion coupons are required to
remain in the gas stream continuously. The regulations do, however, state that if coupons are
used they must be checked twice per calendar year and the regulations must be applied in a
manner that gives a logical effect to this twice yearly requirement. At the hearing, TGP
acknowledged that the period between coupon installations ranged from 4 months to nearly 21
months.26 Pipeline gas characteristics, however, are dynamic. Over time the flow within a
pipeline may transition between corrosive and non-corrosive. If the requirement to determine
corrosivity were not continuous, the use of a coupon in a manner that provides only a “snapshot”
observation of a few weeks with year-long gaps in between would fail to capture temporary
increases in corrosivity during the inter-observation period and may not capture cumulative
corrosive rates and trends over time. Similarly, while the company’s use of additional
monitoring technology27 may have provided additional information on corrosivity, it too was
non-continuous.
With respect to Coupon S4504, TGP acknowledged that it was removed on January 19, 2005,
and not replaced at that location until January 20, 2006. At the hearing, TGP stated that on
May 19, 2005, its SME evaluated the first coupon, on September 20, 2005 the company
scheduled a replacement coupon for installation the next month, and sometime later the “re-
evaluate immediately” marking inadvertently and erroneously overwrote the SME’s conflicting
recommendation.28 Therefore, in this instance TGP did not execute its EM coupon monitoring in
22 Id. at 5-6.
23 Hearing Presentation at 49.
24 Id.
25 This NACE standard is not incorporated by reference into Part 192 and is therefore not enforceable. It does,
however, shed some light on the industry consensus about the technical basis underlying the need for continuous
monitoring.
26 Hearing Presentation at 39-43.
27 Id. at 41.
28 Id. at 59-61.



8
accordance with its own schedule in place at the time.
Having considered TGP’s arguments, I am not persuaded that any advantages of using EM
coupons on a short-term basis obviate the need for continuous monitoring if coupons are being
used in a corrosion control monitoring program.29 It should be noted, however, that nothing in
this decision forbids the use of EM coupons. For example, EM coupons could be used
continuously (of course they would have to be replaced more frequently than weight-loss
coupons) or a one month EM coupon could be used in-between a series of weight-loss coupons
as long as there are no periods in which no coupon is installed at a location where the operator
has previously determined a coupon is needed.
Accordingly, after considering all the evidence and the legal issues presented, I find that
Respondent violated 49 C.F.R. §§ 192.475(a) and 192.477 by failing to use the corrosion
coupons in its internal corrosion control monitoring program in a manner that effectively
monitored for potential corrosive effects insofar as Coupon S4504 was removed on
January 19, 2005, and not replaced until January 20, 2006, and as a result Respondent did not
meet the requirement that if coupons are used they must be checked two times per year. To the
extent that Respondent’s explanation about the impact of Hurricanes Katrina and Rita on the
timing of the coupon replacement may constitute mitigating circumstances, it will be discussed
in the Assessment of Penalty section below.
ASSESSMENT OF PENALTY
Under 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed
$100,000 per violation for each day of the violation, up to a maximum of $1,000,000 for any
related series of violations. In determining the amount of a civil penalty under
49 U.S.C. § 60122 and 49 C.F.R. § 190.225, I must consider the following criteria: the nature,
circumstances, and gravity of the violation, including adverse impact on the environment; the
degree of Respondent’s culpability; the history of Respondent’s prior offenses; Respondent’s
ability to pay the penalty and any effect that the penalty may have on its ability to continue doing
business; and the good faith of Respondent in attempting to comply with the pipeline safety
regulations. In addition, I may consider the economic benefit gained from the violation without
any reduction because of subsequent damages, and such other matters as justice may require.
The Notice proposed a total civil penalty of $28,000 for the violations cited above.
Item 5: The Notice proposed a civil penalty of $18,000 for Respondent’s violation of
49 C.F.R. §§ 192.475(a) and 192.477, for failing to conduct its internal corrosion control
monitoring program in a manner that effectively determined that any internal corrosion was
being minimized. As set forth above, I found that with respect to the allegation that Respondent
failed to place its corrosion coupons in locations where they would be effective, OPS did not
meet its burden of proving this aspect of the allegations and I have withdrawn it. Accordingly, I
find that a proportional reduction in the penalty amount proposed in the Notice is warranted for
this aspect of the allegation.
29 TGP’s semantic distinction between “corrosion detection” and “corrosion monitoring” does not alter this
conclusion.



9
This brings us to Respondent’s violation of 49 C.F.R. §§ 192.475(a) and 192.477 insofar as
Coupon S4504 was removed on January 19, 2005, and not replaced until January 20, 2006. In its
Response, TGP explained that a conflict between the immediate replacement recommendation
generated by its software program and a subsequent determination made by its SME contributed
to the failure to replace the coupon immediately.30 TGP also noted that Hurricanes Katrina and
Rita struck the Gulf of Mexico respectively on August 29, 2005, and September 24, 2005, and
that this contributed to coupon S5340 not being installed until January 20, 2006.31
With respect to the nature, circumstances, and gravity of this violation, when a corrosion control
monitoring program is put in place, failure to carry it out in an effective manner can have a
significant impact on safety. Respondent is culpable for this violation despite the subsequent
improvements in its internal software system; such subsequent actions do not constitute a good-
faith effort to comply prior to the violation. I recognize that Hurricanes Katrina and Rita
occurred in 2005, but both occurred over seven months after the previous coupon was removed
and does not diminish Respondent’s culpability at the time of the violatio
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