# ENBRIDGE PIPELINES (OZARK) L.L.C. — Notice of Probable Violation

- **operation:** document
- **citation:** CPF 420135004
- **title:** ENBRIDGE PIPELINES (OZARK) L.L.C. — Notice of Probable Violation
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2013-03-04
- **effective on:** Not available
- **summary:** CLOSED notice of probable violation citing 195.432(b), 195.565, 195.571, 195.581.
- **machine formats:** - **json:** https://regulus.evalyn.ai/document/phmsa-enforcement-420135004.json
- **markdown:** https://regulus.evalyn.ai/document/phmsa-enforcement-420135004.md
- **app url:** https://regulus.evalyn.ai/document/phmsa-enforcement-420135004
- **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/420135004
**body:**

Notice of Probable Violation involving ENBRIDGE PIPELINES (OZARK) L.L.C.. PHMSA's enforcement data identifies the cited regulations as 195.432(b),  195.565,  195.571,  195.581. The case was opened on 2013-03-04 and is reported as closed as of 2016-11-07. Proposed civil penalty: $78,700. Assessed civil penalty: $45,000. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

420135004_Closure Letter_ 11072016_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420135004/420135004_Closure%20Letter_%2011072016_text.pdf

420135004_Closure Letter_11072016.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420135004/420135004_Closure%20Letter_11072016.pdf

420135004_Decision on the Petition for Reconsideration_09022016.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420135004/420135004_Decision%20on%20the%20Petition%20for%20Reconsideration_09022016.pdf

420135004_Decision on the Petition for Reconsideration_09022016_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420135004/420135004_Decision%20on%20the%20Petition%20for%20Reconsideration_09022016_text.pdf

420135004_Final Order_10162015.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420135004/420135004_Final%20Order_10162015.pdf

420135004_Final Order_10162015_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420135004/420135004_Final%20Order_10162015_text.pdf

420135004_NOPV PCP PCO_03042013.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420135004/420135004_NOPV%20PCP%20PCO_03042013.pdf

420135004_NOPV PCP PCO_03042013_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420135004/420135004_NOPV%20PCP%20PCO_03042013_text.pdf

420135004_Operator Petition For Reconsideration_11062015.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420135004/420135004_Operator%20Petition%20For%20Reconsideration_11062015.pdf

420135004_Operator Response to Notice_04262013.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420135004/420135004_Operator%20Response%20to%20Notice_04262013.pdf

420135004_NOPV PCP PCO_03042013_text.pdf

NOTICE OF PROBABLE VIOLATION
PROPOSED CIVIL PENALTY
and
PROPOSED COMPLIANCE ORDER
CERTIFIED MAIL - RETURN RECEIPT REQUESTED
March 4, 2013
Mr. Richard Adams
Vice President, U. S. Operations
Enbridge Pipelines, LLC
City Center Office
1409 Hammond Ave.
Superior, WI 54880-5247
CPF 4-2013-5004
Dear Mr. Adams:
In November 2011, a representative of the Pipeline and Hazardous Materials Safety
Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code inspected your
Enbridge Pipeline, LLC Cushing Terminal (Enbridge) in Cushing, OK.
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. §195.432 Inspection of in-service breakout tanks.
(b) Each operator must inspect the physical integrity of in-service atmospheric and low-
pressure steel aboveground breakout tanks according to API Standard 653
(incorporated by reference, see § 195.3). However, if structural conditions prevent
access to the tank bottom, the bottom integrity may be assessed according to a plan
included in the operations and maintenance manual under § 195.402(c)(3).



API Standard 653 “Tank Inspection, Repair, Alteration, and Reconstruction” (3rd edition,
December 2001, includes addendum 1 (September 2003), addendum 2 (November 2005),
addendum 3 (February 2008), and errata (April 2008)).
6.3.2.1 All tanks shall be given a visual external inspection by an authorized inspector.
This inspection shall be called the external inspection and must be conducted at least
every 5 years or RCA/4N years (where RCA is the difference between the measured shell
thickness and the minimum required thickness in mils, and N is the shell corrosion rate in
mils per year) whichever is less. Tanks may be in operation during this inspection.
(d) The intervals of inspection specified by documents referenced in paragraphs (b) and (c) of
this section begin on May 3, 1999, or on the operator's last recorded date of the inspection,
whichever is earlier.
Enbridge did not properly determine the shell corrosion rates necessary to establish the
external inspection intervals as required by API Standard 653, 6.3.2.1, incorporated by
reference into Part 195. Paragraph 6.3.2.1 of API Standard 653 requires the external
inspection interval to be determined by subtracting the minimum required shell thickness from
the measured shell thickness and dividing the result by four times the actual shell corrosion
rate. The shell corrosion rate is calculated by dividing the measured metal loss by the time
over which it occurred. The metal loss is determined by subtracting a more recent shell
thickness measurement from a shell thickness measurement made earlier in time at the same
location on the breakout tank. The change in shell thickness is then divided by the time
interval between measurements to determine a corrosion rate. Some of the Enbridge
calculations of metal loss were negative, indicating the shell plate had increased in thickness
over time. This occurred because the methodology used by Enbridge to measure the shell
plate thickness was flawed. Consequently, tanks #1014, #2228, and #3011 had improperly
calculated inspection intervals.
2. §195.432 Inspection of in-service breakout tanks.
(b) Each operator must inspect the physical integrity of in-service atmospheric and low-
pressure steel aboveground breakout tanks according to API Standard 653
(incorporated by reference, see § 195.3). However, if structural conditions prevent
access to the tank bottom, the bottom integrity may be assessed according to a plan
included in the operations and maintenance manual under § 195.402(c)(3).
(d) The intervals of inspection specified by documents referenced in paragraphs (b) and
(c) of this section begin on May 3, 1999, or on the operator's last recorded date of the
inspection, whichever is earlier.
2



API Standard 653 “Tank Inspection, Repair, Alteration, and Reconstruction” (3rd
edition, December 2001, includes addendum 1 (September 2003), addendum 2
(November 2005), addendum 3 (February 2008), and errata (April 2008)).
6.9.3.2 It is the responsibility of the owner/operator to review the inspection findings and
recommendations, establish a repair scope, if needed, and determine the appropriate
timing for repairs, monitoring, and/or maintenance activities. Typical timing
considerations and examples of repairs are: a. Prior to returning the tank to service—
repairs critical to the integrity of the tank (e.g., bottom or shell repairs). b. After the
tank is returned to service—minor repairs and maintenance activity (e.g., drainage
improvement, painting, gauge repairs, grouting, etc.). c. At the next scheduled internal
inspection—predicted or anticipated repairs and maintenance (e.g., coating renewal,
planned bottom repairs, etc.). d. Monitor condition for continued deterioration—(e.g.,
roof and/or shell plate corrosion, settlement, etc.). The owner/operator shall ensure that
the disposition of all recommended repairs and monitoring is documented in writing and
that reasons are given if recommended actions are delayed or deemed unnecessary.
4.5.2 Foundation Repair or Replacement
4.5.2.1 If there is a need for foundation repair or replacement, foundations shall be
restored to the tolerance limits of 10.5.6.
4.5.2.2 Concrete pads, ringwalls, and piers, showing evidence of spalling, structural
cracks, or general deterioration, shall be repaired to prevent water from entering the
concrete structure and corroding the reinforcing steel.
C.1.1.1 Concrete Ring
d. Check that runoff rainwater from the shell drains away from tank.
C.1.1.5 Site Drainage
a. Check site for drainage away from the tank and associated piping and manifolds.
Enbridge did not complete some breakout tank repairs identified by the API 653 standard and
the required inspections as necessary to maintain a tank condition suitable for safe operation
or in the alternative provide engineering justification for not making the repairs. The issues
include failing to make repairs to cracked or deteriorated ringwalls and failing to modify the
grade so that water drains away from the tanks. Inadequate repairs were found on tanks
#1014, #1015, #1016, #1153, and #1154.
3. §195.432 Inspection of in-service breakout tanks.
(b) Each operator must inspect the physical integrity of in-service atmospheric and low-
pressure steel aboveground breakout tanks according to API Standard 653
(incorporated by reference, see § 195.3). However, if structural conditions prevent
access to the tank bottom, the bottom integrity may be assessed according to a plan
included in the operations and maintenance manual under § 195.402(c)(3).
3



(d) The intervals of inspection specified by documents referenced in paragraphs (b) and
(c) of this section begin on May 3, 1999, or on the operator's last recorded date of the
inspection, whichever is earlier.
API Standard 653 “Tank Inspection, Repair, Alteration, and Reconstruction” (3rd
edition, December 2001, includes addendum 1 (September 2003), addendum 2
(November 2005), addendum 3 (February 2008), and errata (April 2008)).
6.3.1.2 The interval of such inspections shall be consistent with conditions at the
particular site, but shall not exceed one month.
Enbridge did not perform the monthly inspections of its breakout tanks as required by 49 CFR
195 and API Standard 653, incorporated by reference. According to the Enbridge Work Order
List Report for monthly breakout tank inspections, breakout tank 1181 was inspected on
January 4, 2011 but not inspected again until March 1, 2011, a span of 56 days with no
February inspection. Breakout tank 1182 was inspected on January 29, 2011 but not inspected
again until March 7, 2011, a span of 37 days with no February inspection. The January Work
Order List indicates that breakout tank 3364 was not inspected until February 1 but inspected
again on February 28 with no January inspection. There are several additional Cushing
Terminal breakout tanks where the inspections are not being performed according to the API
Standard 653 requirement. Enbridge must modify its inspection schedule to meet the
requirement of performing API Standard 653 routine in-service inspections.
4. §195.565 How do I install cathodic protection on breakout tanks?
After October 2, 2000, when you install cathodic protection under Sec. 195.563(a) to
protect the bottom of an aboveground breakout tank of more than 500 barrels
(79.5m3) capacity built to API Specification 12F, API Standard 620, or API Standard
650 (or its predecessor Standard 12C), you must install the system in accordance with
API Recommended Practice 651. However, installation of the system need not comply
with API Recommended Practice 651 on any tank for which you note in the corrosion
control procedures established under Sec. 195.402(c)(3) why compliance with all or
certain provisions of API Recommended Practice 651 is not necessary for the safety of
the tank.
§195.571 What criteria must I use to determine the adequacy of cathodic protection?
Cathodic protection required by this Subpart must comply with one or more of the
applicable criteria and other considerations for cathodic protection contained in
paragraphs 6.2 and 6.3 of NACE SP 0169 (incorporated by reference, see § 195.3).
4



Enbridge did not meet at least one of the applicable criteria for cathodic protection on some
Cushing Terminal breakout tanks as required by API RP 651 and NACE SP 0169. The
Operator uses the 100 mV polarization criterion on a portion of the breakout tanks and the
-850 mV with consideration of IR drop criterion on others. The inspection found several
breakout tanks where Enbridge was not meeting the specified criteria or had not taken the
appropriate measurements to determine if the specified criterion was being met.
For example, Enbridge states that the 100mV criterion is being used tank #1153 but only
energized (on) readings were taken during the 2011 annual survey. To determine if the 100
mV criterion is being met, the operator must compare the polarized measurement, eliminating
IR drop, (instant off) to the depolarized measurement. However, no instant off readings were
taken in 2011 to determine if the 100mV of polarization was achieved. Without instant off
readings, the only check that can be made is against the -850mV with consideration of IR drop
criterion (energized reading). Several of the energized readings taken using the profile tube
did not meet the -850mV criterion even before considering IR drop (20 feet, -625mV, 25 feet,
-607mV, 30 feet, -684mV, 40 feet, -702mV).
As another example, the records for tank #1295 do not show any depolarization measurements
so one of the -850mV criteria must be applied. Some of the structure-to-soil measurements
did not meet either of the -850mV criteria listed in NACE SP0169 or API RP651 for 2009,
2010, or 2011. Enbridge records indicate that a new groundbed was installed in 2010 but
some of the 2011 structure-to-soil readings were still not meeting one of the -850 mV criteria.
Tank #2211, which was cited in a previous enforcement action (CPF 4-2010-5008) for
exceeding the API 653 internal inspection interval, was diagnosed with a depleted groundbed
as early as 2007. The tank was scheduled to be taken out of service in 2012 but Enbridge
continued to operate the tank with deficient cathodic protection in 2009, 2010, and 2011.
Other examples of tanks not meeting one of the cathodic protection criteria include #1182,
#2218, #1320, #2212, #2215, and #2223.
5. §195.581Which pipelines must I protect against atmospheric corrosion and what
coating material may I use?
You must clean and coat each pipeline or portion of pipeline that is exposed to the
atmosphere, except pipelines under paragraph (c) of this section. (b) Coating
material must be suitable for the prevention of atmospheric corrosion. (c) Except
portions of pipelines in offshore splash zones or soil-to-air interfaces, you need not
protect against atmospheric corrosion any pipeline for which you demonstrate by
test, investigation, or experience appropriate to the environment of the pipeline that
corrosion will- (1) Only be a light surface oxide; or (2) Not affect the safe operation
of the pipeline before the next scheduled inspection.
5



§195.583 What must I do to monitor atmospheric corrosion control?
(c) If you find atmospheric corrosion during an inspection, you must provide
protection against the corrosion as required by Sec. 195.581.
Enbridge has not consistently applied coating material (paint) to all of its breakout tanks in the
Cushing Terminal suitable for the prevention of atmospheric corrosion as required by
195.581(a). Enbridge has several tanks at their Cushing, OK terminal that have not been
completely painted and have an atmospheric corrosion scale on the unpainted exterior surface.
Enbridge argues that the corrosion scale is a form of protective coating and that the tanks do
not need to be painted to protect them from atmospheric corrosion. However, according to the
Operator, the bottom four feet on these tanks has been painted “to protect the floor-to-shell
(“chime”) weld and appurtenance area.” The acknowledgment that a portion of the tank had to
be painted for protection from atmospheric corrosion indicates that corrosion damage is
occurring and constitutes a contradiction to the Operator’s argument that the corrosion scale is
adequate protection from atmospheric corrosion.
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 $78,700 as follows:
Item number PENALTY
1 $33,700
4 $45,000
Warning Items
With respect to item(s) 2, 3, and 5 we have reviewed the circumstances and supporting
documents involved in this case and have decided not to conduct additional enforcement action
or penalty assessment proceedings at this time. We advise you to promptly correct these item(s).
Be advised that failure to do so may result in Enbridge Pipeline being subject to additional
enforcement action.
Proposed Compliance Order
With respect to item(s) 1 and 4 pursuant to 49 United States Code § 60118, the Pipeline and
Hazardous Materials Safety Administration proposes to issue a Compliance Order to Enbridge
Pipeline. Please refer to the Proposed Compliance Order, which is enclosed and made a part of
this Notice.
6



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 4-2013-5004 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
7



PROPOSED COMPLIANCE ORDER
Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety
Administration (PHMSA) proposes to issue to Enbridge a Compliance Order incorporating the
following remedial requirements to ensure the compliance of Enbridge with the pipeline safety
regulations:
1. 2. 3. 4. In regard to Item Number 1 of the Notice pertaining to improperly determining
the shell corrosion rates, Enbridge must modify its program to correctly determine
the shell thicknesses and corrosion rates on all of the breakout tanks in the
Cushing Terminal and re-determine the external inspection intervals for each
breakout tank.
In regard to Item Number 4 of the Notice pertaining to failing to achieve adequate
cathodic protection on some of the breakout tanks and piping in the Cushing
Terminal, Enbridge must take appropriate actions to remedy all cathodic
protection deficiencies and show by structure-to-soil measurements that one or
more of the cathodic protection criteria listed in NACE SP0169 or API RP651 has
been achieved.
In regard to Item Number 1 of the Notice, Enbridge must submit, for PHMSA
approval, a shell thickness measurement procedure within 30 days of receipt of
this Order. The Operator must then complete shell thickness re-measurements
according to the approved procedure for all Cushing Terminal breakout tanks
within 180 days of receiving PHMSA approval for the procedure. The Operator
must also propose an initial shell re-measurement interval appropriate to
determine a valid shell corrosion rate, and once the second measurement has been
completed, recalculate the external inspection interval for all Cushing Terminal
breakout tanks. Enbridge must complete the entire process to properly determine
the external inspection intervals within 60 months from of receipt of this Order.
In regard to Item Number 4 of the Notice, Enbridge must submit to PHMSA, a
plan, with dates, to correct all cathodic protection deficiencies within 30 days of
receipt of this Order. The Operator must complete correction of all deficiencies
within 12 months of receipt of this Order.
It is requested (not mandated) that Enbridge Pipeline, LLC 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. It is requested
that these costs 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.
8

420135004_Decision on the Petition for Reconsideration_09022016_text.pdf

September 2, 2016
Mr. Mark Maki
President
Enbridge Pipelines (Ozark), LLC
1100 Louisiana Street
Suite 3300
Houston, TX 77002
Re: CPF No. 4-2013-5004
Dear Mr. Maki:
Enclosed is the Decision on the Petition for Reconsideration filed by Enbridge Pipelines (Ozark),
LLC, in the above-referenced case. For the reasons explained therein, the Decision grants the
Petition and modifies the civil penalty and compliance terms of the October 16, 2015 Final
Order. The penalty terms are set forth in the Decision. When the civil penalty has been paid and
the terms of the compliance order completed, as determined by the Director, Southwest Region,
this enforcement action will be closed. This Decision constitutes the final administrative action
in this proceeding. Service of this Decision is made pursuant to 49 C.F.R. § 190.5.
Thank you for your cooperation in this matter.
Sincerely,
Alan K. Mayberry
Acting Associate Administrator
for Pipeline Safety
Enclosure
cc: Mr. R. M. Seeley, Regional Director, Southwest Region, OPS
Mr. Darren Hunter, Counsel for Enbridge Pipelines (Ozark), LLC, Rooney Rippie &
Ratnaswamy, LLP, Kingsbury Center, Suite 600, 350 W. Hubbard Street, Chicago,
Illinois 60654
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 )
)
Enbridge Pipelines (Ozark), LLC, ) CPF No. 4-2013-5004
a subsidiary of Enbridge, Inc., )
)
Petitioner. )
____________________________________)
DECISION ON PETITION FOR RECONSIDERATION
In November 2011, pursuant to 49 U.S.C. § 60117, a representative 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 Enbridge Pipelines
(Ozark), LLC (Enbridge or Petitioner), at the company’s Cushing Terminal in Cushing,
Oklahoma. The Cushing Terminal includes 87 crude oil storage tanks with approximately 20
million barrels in shell capacity.1
As a result of the inspection, the Director, Southwest Region, OPS (Director), issued a Notice of
Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (Notice) to
Enbridge on March 3, 2013, which alleged certain violations of the pipeline safety regulations
and proposed a civil penalty of $78,700.2 The Notice also proposed ordering Petitioner to take
certain measures to correct the alleged violations.
Enbridge responded to the Notice by letter dated April 26, 2013 (Response).3 The company
contested one of the allegations of violation, provided certain information regarding the
corrective actions it had taken, but did not request a hearing.4
On October 16, 2015, pursuant to 49 C.F.R. § 190.213, PHMSA issued a Final Order in this
proceeding.5 The agency found that Enbridge had committed violations of § 195.432(b) (Item 1)
1 See www.enbridge.com. Current as of May 9, 2016.
2 Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (Notice), C.P.F. No. 4-
2013-5004, (Mar. 4, 2013) (on file with PHMSA).
3 Respondent’s Response to Notice (Response), (Apr. 26, 2013) (on file with PHMSA).
4 Id.



CPF No. 4-2013-5004
Page 2
and §§ 195.565 and 195.571 (Item 4), as alleged in the Notice.6 The Final Order assessed a civil
penalty of $33,700 for Item 1 and $45,000 for Item 4 and ordered corrective actions for both
items, set forth in the compliance order that was part of the Final Order.7 The Final Order also
issued warnings for probable violations of 49 C.F.R. § 195.432 (b) and (c) (Items 2 and 3) and §
195.581 (Item 5).8
In accordance with § 190.243, Enbridge filed a timely Petition for Reconsideration of the Final
Order on November 9, 2015, seeking reconsideration of the finding of violation in Item 1 and its
associated civil penalty and compliance terms.9 For the reasons stated below, I find that the
finding of violation, civil penalty and compliance terms for Item 1 should be withdrawn for lack
of sufficient evidence. Accordingly, as noted below, I am granting the Petition by withdrawing
Item 1 of the Final Order in its entirety. The other provisions of the Final Order are otherwise
affirmed without modification.
Standard of Review
Pursuant to 49 C.F.R. § 190.243, an operator may petition for reconsideration of a final order
issued under § 190.213 and PHMSA may consider additional facts or arguments if the petitioner
submits a valid reason explaining why such information was not presented prior to issuance of
the final order. PHMSA may grant or deny, in whole or in part, a petition for reconsideration
without further proceedings, but may request additional information or comment if deemed
appropriate.
Discussion
Item 1 in the Final Order found that Petitioner violated 49 C.F.R. § 195.432(b), which states:
§ 195.432 Inspection of in-service breakout tanks.
(a) …
(b) Each operator must inspect the physical integrity of in-service
atmospheric and low-pressure steel aboveground breakout tanks according
to API Standard 653 (incorporated by reference, see § 195.3). However, if
structural conditions prevent access to the tank bottom, the bottom
integrity may be assessed according to a plan included in the operations
and maintenance manual under § 195.402(c)(3).
5 In the Matter of Enbridge Pipelines (Ozark), LLC, Final Order, C.P.F. No. 4-2013-5004 (Oct. 16, 2015) (Final
Order) (available at www.phmsa.dot.gov/pipeline/enforcement).
6 Id.
7 Id.
8 Id.
9 Petitioner’s Petition for Reconsideration (Petition), (Nov. 9, 2015) (on file with PHMSA). Enbridge did not seek
reconsideration of Items 2 through 5.



CPF No. 4-2013-5004
Page 3
The Final Order determined the Petitioner had violated § 195.432(b) by failing to inspect the
physical integrity of three in-service breakout tanks at its Cushing, Oklahoma facility, in
accordance with American Petroleum Institute (API) Standard 653 (Standard).10 Specifically,
PHMSA found that the Petitioner violated section 6.3.2.1 of the Standard by failing to properly
determine the corrosion growth rates for several tanks in the Cushing facility.11 To illustrate, the
Final Order noted that recorded shell-plate corrosion growth rates for three tanks in the Cushing
facility were negative, indicating the methodology used by the Petitioner was flawed and
inconsistent with the Standard.12 The Final Order further explained that even when considering
pertinent variables such as steel tolerances and measurement differentials, the Petitioner’s
methodology could only be effective if corrosion rates were completely uniform across the
tanks.13 The Order also found that the negative values showed the company’s methodology for
calculating the corrosion growth rates was not in accordance with sound engineering principles.
In its Petition, Enbridge contends it did not violate § 195.432(b) and PHMSA wrongly concluded
that the negative corrosion growth rates recorded for the three Cushing Terminal tanks implied
that the company had employed an incorrect methodology.14 Enbridge argues that it applied the
formula for corrosion growth rates as prescribed in the Standard and that the recorded negative
values did not indicate noncompliance. Enbridge explains that it calculated metal loss, a
component of the corrosion growth-rate calculation, by using the minimum (thinnest) thickness
measurement taken on each tank and comparing it to the thickness measurements from the
previous inspection for each tank.15 Enbridge further explains that using the minimum thickness
measurement “add[ed] conservatism” to the metal-loss and corrosion-rate calculations.16
In its Petition, Enbridge further argues that the Notice erroneously alleged that the Standard
required corrosion growth rates to be calculated by determining metal loss at the same location
on each tank during each inspection.17 The Petition includes expert opinions stating that
“tak[ing] measurements at random locations on the tank to determine general corrosion rates” is
compliant with the Standard.18
10 API Standard 653, “Tank Inspection Repair, Alteration, and Reconstruction” (3rd edition, December 2001,
includes addendum 1 (September 2003), addendum 2 (November 2005), addendum 3 (February 2008) and errata
(April 2008)), has been incorporated by reference into 49 C.F.R. Part 195 under 49 C.F.R. § 195.3.
11 Final Order, at 2.
12 Id. at 3.
13 Id.
14 Petition, at 3.
15 Petition, at 3-4; Response, at 2.
16 Response, at 2.
17 Petition, at 3.
18 Id. at 4.



CPF No. 4-2013-5004
Page 4
The crux of this Petition involves the question of what constitutes the proper methodology for
calculating external inspection intervals and tank-shell corrosion growth rates, which are
prescribed by the Standard. Section 6.3.2.1 of the Standard states that external inspections shall
occur at least every five years, or RCA/4N years (where RCA is the difference between the
measured shell thickness and the minimum required thickness in shells, and N is the shell
corrosion rate in mils per year), whichever is less. Section 3.11 of the Standard defines corrosion
rate (N) as “[t]he total metal loss divided by the period of time over which the metal loss
occurred.” To calculate the corrosion rate (N) for a tank shell, metal loss must first be
determined. The Standard, however, does not prescribe a specific methodology for calculating
metal loss, nor does it specify a methodology for determining the thicknesses of tank shell-plates,
an essential component of the metal loss calculation.
In this case, OPS bears the burden of proving, by a preponderance of the evidence, that the
Petitioner failed to calculate the inspection interval in accordance with the Standard. The “Shell
Thickness Evaluation” reports (Reports) provided by the Petitioner during the PHMSA
inspection show that the inspection intervals for the three tanks at issue were set at five years or
less.19 The reports show that Enbridge had recorded shell-plate thickness measurements for each
course of the individual tanks during the most recent inspections.20 The evidence does not reflect
that Enbridge inspectors took more than a single shell-plate thickness measurement for each tank
course; however, the Petitioner asserts that several shell-plate thickness measurements were
taken and the smallest (thinnest) readings were recorded in the report as the thickness
determinations for each course.21 Further, the Reports show that corrosion rates were calculated
for each tank course based on these minimum shell-plate thickness readings by utilizing the
formula prescribed in Section 3.11 of the Standard, total metal loss divided by the period of time
over which the metal loss occurred.22 The Reports also show that the formula prescribed in
Section 6.3.2.1 was applied as prescribed in calculating the inspection intervals for the three
subject tanks.23 Finally, the Reports reflect that the ultimate inspection interval for each tank
was based on the shortest interval calculated from all of the individual tanks’ courses.24
19 Pipeline Safety Violation Report (Violation Report), (Jul. 9, 2012), at 39-41.
20 Id.
21 Response, at 2.
22 See Violation Report, at 39, the calculations for Tank 1014 are as follows: RCA = (.593) – (.5198) = .07
corrosion allowance, N = .028 / 5.62 = .0049 mils / year, .07 / 4 (.0049) = 3.73 years (report reflects 3.67 years);
Violation Report at 40, the calculations for Tank 2228 are as follows: RCA = (1.078 ) – (.8910) = .187 corrosion
allowance, N = .091 / 9.80 = .009 mils / year, .187 / 4 (.009) = 5.05 years (report reflects 5.04 years); Violation
Report at 41, the calculations for Tank 3011 are as follows: RCA = (.934) – (.8616) = .0724 corrosion allowance, N
= .038 / 9.08 = .004 mils / year, .0724 / 4 (.004) = 4.525 years (report reflects 3.67 years).
23 Id.
24 Id. at 39-41.



CPF No. 4-2013-5004
Page 5
I have carefully reviewed the entire record in this case and cannot determine that the
methodology used by Enbridge to calculate the tank inspection intervals under the Standard was
wrong or that it violated 49 C.F.R. § 195.432(b). First, I agree with the Petitioner that the
negative corrosion growth rates recorded by Enbridge inspectors do not show that the company’s
methodology was inherently flawed.25 Negligible or negative corrosion rates may occur while
properly employing the corrosion-rate calculation set forth in the Standard, as argued by the
Petitioner and its experts.26 This is because the calculations for tank shell corrosion rates and
metal loss include shell-plate thickness measurements that can be affected by several variables,
including steel tolerances, measurement differentials, and differing rates of corrosion. Those
variables can result in negative metal loss calculations, even when the Standard is followed
appropriately.
Second, I agree with Enbridge that API 653 does not require that shell-plate thickness
measurements be taken at the same location on each tank during each inspection when
determining metal loss. Rather, the Standard is silent on the exact methodology that must be
used for making the metal loss determination. While Enbridge’s methodology of using a
minimum thickness reading for each tank course to determine a general corrosion rate may not
be considered the optimal practice because single, anomalous readings can skew general
corrosion rates, the Petitioner’s methodology did not expressly violate 49 C.F.R. § 195.432 or
API 653.27
The Notice and Final Order found fault with Petitioner’s practice of taking shell-plate thickness
measurements across each tank shell and using the lowest reading in the metal loss calculation
for that tank. While the evidence shows Enbridge inspectors did not calculate the average shell-
plate thicknesses when determining metal loss of the tanks in accordance with sound engineering
practices, the Petitioner’s methodology does not expressly violate the requirements of Sections
6.3.2.1 or 3.11 of the Standard, as neither directly prescribes a methodology for determining
shell-plate thickness measurements. Based on the evidence of record, I find there is insufficient
evidence to show that Enbridge violated either the Standard or § 195.432(b). Accordingly, I
grant the Petition for Reconsideration with respect to Item 1 of the Final Order. The finding of
violation, the proposed penalty of $33,700, and the associated terms of the compliance order are
hereby withdrawn.
25 Id. The Enbridge “Shell Thickness Evaluation” reports include shell corrosion rates for each tank course on the
subject tanks. Several corrosion rates recorded for the tank courses were negative, in negligible amounts.
26 Petition, at 3.
27 Enbridge even argues that “there are variables that affect the [shell corrosion rate] calculation” in support of their
argument that measuring in the same location on each tank is not the correct methodology. Petition, at 5.



CPF No. 4-2013-5004
Page 6
Conclusion
For the reasons stated above, the Petition for Reconsideration is granted. The finding of
violation in Item 1 of the Final Order, the associated penalty of $33,700, and the associated
compliance terms are hereby withdrawn. All other terms of the Final Order and Compliance
Order remain in effect as set forth therein.
This Decision on Reconsideration is the final administrative action in this proceeding.
___________________________________ __________________________
Alan K. Mayberry Date Issued
Acting Associate Administrator
for Pipeline Safety

420135004_Closure Letter_ 11072016_text.pdf

CERTIFIED MAIL – RETURN RECEIPT REQUESTED
November 7, 2016
Mr. Brad Shamla
Vice President, U.S. Operations
Enbridge Storage (Cushing) L.L.C.
1100 Louisiana Street, Suite 3300
Houston, TX 77002
Re: CPF No. 4-2013-5004
Dear Mr. Shamla:
On October 16, 2015, a Final Order was issued in the above-referenced case. The Final Order
made a finding of violation and specified actions to be taken by Enbridge Storage (Cushing)
L.L.C. (Enbridge).
On September 2, 2016, a Decision on the Petition for Reconsideration was issued in the above-
referenced case. The Decision on the Petition for Reconsideration withdrew Item 1 of the Final
Order.
Based on a PHMSA review it has been determined that Enbridge has completed the requirements
of the Final Order. This letter is to inform you that no further action is necessary and this case is
now closed. Thank you for your cooperation.
Sincerely,
R. M. Seeley
Director, Southwest Region
Pipeline and Hazardous Materials Safety Administration

420135004_Final Order_10162015_text.pdf

October 16, 2015
Mr. Mark Maki
President
Enbridge Pipelines (Ozark), LLC
1100 Louisiana Street
Suite 3300
Houston, TX 77002
Re: CPF No. 4-2013-5004
Dear Mr. Maki:
Enclosed please find the Final Order issued in the above-referenced case. It makes findings of
violation, assesses a civil penalty of $78,700, and specifies actions that need to be taken by
Enbridge Pipelines (Ozark), LLC, to comply with the pipeline safety regulations. The penalty
payment terms are set forth in the Final Order. When the civil penalty has been paid and the
terms of the compliance order 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. Rodrick Seeley, Regional Director, Southwest Region, OPS
Mr. Shaun Kavajecz, Senior Manager, US Pipeline Compliance, Enbridge Energy
Company, Inc. 26 E. Superior Street, Suite 309 Duluth, MN 55811
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 )
Enbridge Pipelines (Ozark), LLC, )
a subsidiary of Enbridge, Inc., ) CPF No. 4-2013-5004
)
)
)
Respondent. )
_____________________________________)
FINAL ORDER
During November 2011, pursuant to 49 U.S.C. § 60117, a representative 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 Enbridge Pipelines
(Ozark), LLC (Enbridge or Respondent), at the company’s Cushing Terminal in Cushing,
Oklahoma. Enbridge is a subsidiary of Enbridge, Inc., an international energy company involved
in the generation, transport, storage and distribution of oil, gas and electricity assets, with its
corporate headquarters in Calgary, Canada, and a United States headquarters in Houston, Texas.1
As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to
Respondent, by letter da
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