# CENEX PIPELINE LLC — Notice of Probable Violation

- **operation:** document
- **citation:** CPF 520125013
- **title:** CENEX PIPELINE LLC — Notice of Probable Violation
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2012-05-18
- **effective on:** Not available
- **summary:** CLOSED notice of probable violation citing 195.214(b), 195.401(b)(1), 195.404(a), 195.404(a)(1)(vii), 195.404(b)(1), 195.432(b), 195.452(h), 195.505(b), 195.573(c), 195.575(e), 195.581, 195.583(b).
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- **markdown:** https://regulus.evalyn.ai/document/phmsa-enforcement-520125013.md
- **app url:** https://regulus.evalyn.ai/document/phmsa-enforcement-520125013
- **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/520125013
**body:**

Notice of Probable Violation involving CENEX PIPELINE LLC. PHMSA's enforcement data identifies the cited regulations as 195.214(b),  195.401(b)(1),  195.404(a),  195.404(a)(1)(vii),  195.404(b)(1),  195.432(b),  195.452(h),  195.505(b),  195.573(c),  195.575(e),  195.581,  195.583(b). The case was opened on 2012-05-18 and is reported as closed as of 2014-04-18. Proposed civil penalty: $76,500. Assessed civil penalty: $41,500. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

520125013_closure letter_04182014.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520125013/520125013_closure%20letter_04182014.pdf

520125013_closure letter_04182014_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520125013/520125013_closure%20letter_04182014_text.pdf

520125013_Final Order_12312012.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520125013/520125013_Final%20Order_12312012.pdf

520125013_Final Order_12312012_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520125013/520125013_Final%20Order_12312012_text.pdf

520125013_NOPV PCP PCO_05182012.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520125013/520125013_NOPV%20PCP%20PCO_05182012.pdf

520125013_NOPV PCP PCO_05182012_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520125013/520125013_NOPV%20PCP%20PCO_05182012_text.pdf

520125013_Operator_response_06192012.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520125013/520125013_Operator_response_06192012.pdf

520125013_closure letter_04182014_text.pdf

CERTIFIED MAIL - RETURN RECEIPT REQUESTED
April 18, 2014
Mr. John Traeger
President
Cenex Pipeline, LLC
P.O. Box 909
Laurel, Montana 59044-0909
CPF 5-2012-5013
Dear Mr. Traeger:
On December 31, 2012, the Pipeline and Hazardous Materials Safety Administration (PHMSA)
issued to Cenex Pipeline, LLC a Final Order in the above-referenced case. This Order included a
Compliance Order. Based on our review of the documentation you provided and an on-site
pipeline safety inspection on April 14, 2014, it has been determined that you have complied with
the terms of this Order.
Accordingly, this case is now closed and no further action is contemplated with respect to the
matters involved in this case. Thank you for your cooperation in this matter.
Sincerely,
Chris Hoidal
Director, Western Region
Pipeline and Hazardous Materials Safety Administration
cc: PHP-60 Compliance Registry
PHP-500 M. Petronis

520125013_NOPV PCP PCO_05182012_text.pdf

NOTICE OF PROBABLE VIOLATION
PROPOSED CIVIL PENALTY
and
PROPOSED COMPLIANCE ORDER
CERTIFIED MAIL - RETURN RECEIPT REQUESTED
May 18, 2012
Mr. Daniel Knepper
President and Chief Operating Officer
Cenex Pipeline Company
803 Highway 212 South
P.O. Box 909
Laurel, MT 59044-0909
CPF 5-2012-5013
Dear Mr. Knepper:
Between August 16 and October 29, 2010, representatives of the Pipeline and Hazardous
Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code
inspected Cenex Pipeline Company (Cenex) pipeline operation and maintenance (O&M)
procedures and records in Laurel, Montana. In addition, PHMSA’s representative conducted
field inspections of numerous Cenex pipeline facilities in Montana and North Dakota.
As a result of these inspections, 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 violations are:



1. § 195.214 Welding procedures.
(b) Each welding procedure must be recorded in detail, including the results of the
qualifying tests. This record must be retained and followed whenever the procedure is
used.
Cenex did not record in detail the results of the qualifying tests for their in-service welding
procedure 110504-1. This procedure is used for welding metal repair sleeves to pipe. The
qualifying test records for in-service weld procedure 110504-1 lacked sufficient detail.
Specifically, the test records did not differentiate between tests done for the groove weld and
tests done for the sleeve (fillet) weld. The record showed the force required for the rupture of
two tensile test coupons but the record did not show those coupons’ sizes or the results for the
maximum and minimum tensile stresses that resulted from these tests. API 1104 Table B-1
requires that the groove weld have two tensile tests, two nick-break tests, two root bend tests and
two face bend tests. API 1104 Table B-1 also requires that the sleeve weld have 4 nick-break
tests, 4 face bend tests, and 4 macro tests. The record showed results for two nick-break tests,
two root bend tests, and two face bend tests but the record did not differentiate if these tests were
on the groove weld or sleeve weld. There were no results for sleeve weld macro tests. In
accordance with § 195.214, an operator is required to maintain detailed records of weld
procedure qualification tests.
2. §195.401 General requirements.
(b) An operator must make repairs on its pipeline system according to the following
requirements:
(1) Non Integrity management repairs. Whenever an operator discovers any condition
that could adversely affect the safe operation of its pipeline system, it must correct the
condition within a reasonable time. However, if the condition is of such a nature that it
presents an immediate hazard to persons or property, the operator may not operate the
affected part of the system until it has corrected the unsafe condition.
Cenex failed to correct within a reasonable time a discovered condition that could adversely
affect the safe operation of its Minot Tanks 201 and 202. Specifically, during the 2007 external
inspections of these tanks, Cenex discovered that these tanks would only be suitable for service if
safe fill height recommendations were adhered to. However, during the 2010 inspection, neither
of the inspection reports contained what the safe fill height was for each tank. Without an
established safe fill height, Cenex cannot operate these tanks safely. An operator is required to
correct conditions affecting safe operation of its system in a reasonable time after they discover
the condition.
3. § 195.404 Maps and Records.
(a) Each operator shall maintain current maps and records of its pipeline systems that
include at least the following information;
(1) Location and identification of the following pipeline facilities;
(vii) Safety devices to which §195.428 applies.
2



Cenex did not maintain current maps and records for its North Dakota section of the Cenex
pipeline. Reviews of Cenex’s Piping and Instrumentation Diagrams (P&ID) revealed that Cenex
had not updated the P&IDs for the North Dakota section of the Cenex pipeline with current
pressure safety valve tag numbers. The location of those safety devices cannot be easily
established unless the safety valve tag numbers are shown on the P&IDs. An operator must
maintain current maps and records with the location and identification of safety devices to which
§ 195.428 applies.
4. § 195.404 Maps and Records.
(a) Each operator shall maintain current maps and records of its pipeline systems that
include at least the following information;
(1) Location and identification of the following pipeline facilities;
(i) Breakout tanks;
(ii) Pump stations;
(iv) Pipeline valves;
(v) Facilities to which §195.402(c)(9) applies;
(vi) Rights-of-way; and
(vii) Safety devices to which §195.428 applies.
(2) All crossings of public roads, railroads, rivers, buried utilities, and foreign
pipelines.
(3) The maximum operating pressure of each pipeline.
(4) The diameter, grade, type and nominal wall thickness of all pipe.
At the time of our inspection, Cenex did not have current maps and records of its pipeline
system. The maps and records did not include the location and identification of all the pipeline
features and appurtenances required under §195.404(a). Interviews with Cenex personnel
revealed that it had been 10 years since Cenex had last updated the alignment sheets for the
Cenex pipeline. There has been significant urban development and oil field activity along much
of the Cenex pipeline in the last 10 years. During this time, there has been several pipeline
repairs and replacement projects as well as pump station modifications. An operator must
maintain current maps and records of its systems, including but not limited to, current
information such as new third party crossings, new breakout tanks, and other pipeline changes as
noted under 195.404(a).
5. § 195.404 Maps and Records.
(b) Each operator shall maintain for at least 3 years daily operating records that
indicate-
(1) The discharge pressure at each pump station; and
Cenex did not maintain daily operating discharge pressures for the Billings Tank Farm booster
pump station. Specifically, Cenex did not have a pressure recording device for discharge
pressures at the Billings Tank Farm booster pump, therefore, discharge pressures from this pump
station could not be recorded. The Billings Tank Farm pump station discharges product into a
pipeline section that carries it to the suction side of the Billings pump station, approximately 2.5
miles downstream from the Billings Tank Farm pump station. This section of pipeline crosses
3



the Yellowstone River and traverses property that is not under the control of Cenex. An operator
must maintain at least three years of daily discharge pressures at each pump station and therefore
must maintain a discharge pressure recording device that will allow the operator to record those
daily discharge records.
6. § 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).
Cenex failed to perform external tank inspections for eight (8) of their breakout tanks within the
maximum 5 year interval, in accordance with API 653 Section 6.3.2.1, either after 1) the
previous external tank inspection or 2) May 3, 1999, the effective date of § 195.432(b),
whichever came later. Cenex records show that the following breakout tanks’ external
inspection intervals were exceeded by the following time periods.
Cenex Breakout Tank
Identifier
API 653 external
inspection deadlines
Actual API 653
external inspection
completion date
Time period that
Cenex exceeded the
interval for API 653
external inspections
Billings Tank 283 May 2004 September 2008 51months
Billings Tank 284 April 2006 October 2009 41months
Minot Tank 202 May 2004 November 2007 41 months
Minot Tank 203 June 2005 November 2007 28 months
Minot Tank 204 June 2006 November 2007 16 months
Minot Tank 207 May 2004 November 2007 41 months
Minot Tank 209 May 2004 November 2007 41 months
Minot Tank 210 June 2005 November 2007 28 months
In accordance with § 195.432 and the referenced standard, API 653 6.3.2.1, an operator is
required to perform external inspections of all breakout tanks at an interval that may not exceed 5
years.
7. § 195.452 Pipeline integrity management in high consequence areas.
(h) What actions must an operator take to address integrity issues?
(1) General requirements. An operator must take prompt action to address all
anomalous conditions the operator discovers through the integrity assessment or
information analysis. In addressing all conditions, an operator must evaluate all
anomalous conditions and remediate those that could reduce a pipeline's integrity. An
operator must be able to demonstrate that the remediation of the condition will ensure
the condition is unlikely to pose a threat to the long-term integrity of the pipeline. An
operator must comply with § 195.422 when making a repair….
(4) Special requirements for scheduling remediation
4



(ii) 60-day conditions. Except for conditions listed in paragraph (h)(4)(i) of this section,
an operator must schedule evaluation and remediation of the following conditions
within 60 days of discovery of condition.
(A) A dent located on the top of the pipeline (above the 4 and 8 o'clock positions) with a
depth greater than 3% of the pipeline diameter (greater than 0.250 inches in depth for a
pipeline diameter less than Nominal Pipe Size (NPS) 12).
(B) A dent located on the bottom of the pipeline that has any indication of metal loss,
cracking or a stress riser.
(iii) 180-day conditions. Except for conditions listed in paragraph (h)(4)(i) or (ii) of this
section, an operator must schedule evaluation and remediation of the following within
180 days of discovery of the condition:
(A) A dent with a depth greater than 2% of the pipeline's diameter (0.250 inches in
depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth
weld or a longitudinal seam weld.
Cenex failed to evaluate all dent anomalies within HCAs. Specifically, Cenex did not account
for the in-line inspection tool’s accuracy when determining which anomalies required further
investigation. During inspection interviews, Cenex acknowledged that they did not add the in-
line inspection tool vendor’s reported tool tolerance to identified dent depths. During two
deformation tool runs conducted in 2008, several dents were repaired but 16 dents were
discovered within HCAs that would have had indications deeper than .25 inches had the tool
vendor’s advertised accuracies been added to these dent’s reported depths. Subsequently these
dents were not reported to be greater than .25 inches so they were not properly evaluated. The
ID#s for the dents found during the Glendive Station to Minot Station in-line inspection are
14000022, 14000048, 14000027, 14000034, 14000051, 14000012, 14000013, 14000023,
14000069, 14000019, 14000076, 14000068, 14000058, and 14000060. The ID#s for the dents
found during the Laurel Station to Billings Station in-line inspection are 14000003 and
14000004.
Cenex’s vendor’s published deformation tool accuracy had a declared confidence level of ± 1%
of the nominal outside diameter (OD) of the pipe 80% of the time. Both of these pipeline
sections had a nominal OD of 8.625 inches. 1% of 8.625 inches is ±.09 inches. Allowing for the
vendor’s advertised accuracies makes it possible that a dent reported as greater than .16 inches
could actually be deeper than .25 inches. Taking into account the deformation tool accuracy, any
deformation that was recorded on the deformation tool log that was found greater than .16 inches
should have been evaluated to determine if the criteria under §195.452(h)(4)(ii) or
§195.452(h)(4)(iii) had been met. If found to meet that criteria, these deformations should have
been investigated, precisely measured and repaired if required. The annotated deformation logs
provided by Cenex for the Glendive to Minot run and for the Laurel to Billings Station runs
shows that there were 16 deformation tool dent calls greater than .16 inches within an HCA
which were not properly evaluated, investigated, or repaired. An operator is required to evaluate
any dent greater than .25 inches on pipe that is less than Nominal Pipe Size (NPS) 12 when the
dent is located on the top of the pipeline or when the dent affects pipe curvature at a girth weld or
a longitudinal seam weld. If the dent meets any of those criteria, the operator must repair that
dent.
5



8. § 195.452 Pipeline integrity management in high consequence areas.
(h) What actions must an operator take to address integrity issues?
(1) General requirements. An operator must take prompt action to address all
anomalous conditions the operator discovers through the integrity assessment or
information analysis. In addressing all conditions, an operator must evaluate all
anomalous conditions and remediate those that could reduce a pipeline's integrity. An
operator must be able to demonstrate that the remediation of the condition will ensure
the condition is unlikely to pose a threat to the long-term integrity of the pipeline. An
operator must comply with § 195.422 when making a repair….
(4) Special requirements for scheduling remediation--
(i) Immediate repair conditions. An operator's evaluation and remediation schedule
must provide for immediate repair conditions. To maintain safety, an operator must
temporarily reduce operating pressure or shut down the pipeline until the operator
completes the repair of these conditions. An operator must calculate the temporary
reduction in operating pressure using the formula in Section 451.6.2.2 (b) of ANSI/
ASME B31.4 (incorporated by reference, see § 195.3). An operator must treat the
following conditions as immediate repair conditions….
(B) A calculation of the remaining strength of the pipe shows a predicted burst
pressure less than the established maximum operating pressure at the location of the
anomaly. Suitable remaining strength calculation methods include, but are not limited
to, ASME/ANSI B31G (``Manual for Determining the Remaining Strength of Corroded
Pipelines'' (1991) or AGA Pipeline Research Committee Project PR-3-805 (``A
Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe''
(December 1989)). These documents are incorporated by reference and are available at
the addresses listed in Sec. 195.3….
(iii) 180-day conditions. Except for conditions listed in paragraph (h)(4)(i) or (ii) of this
section, an operator must schedule evaluation and remediation of the following within
180 days of discovery of the condition:
(D) A calculation of the remaining strength of the pipe shows an operating pressure
that is less than the current established maximum operating pressure at the location of
the anomaly. Suitable remaining strength calculation methods include, but are not
limited to, ASME/ANSI B31G (``Manual for Determining the Remaining Strength of
Corroded Pipelines'' (1991)) or AGA Pipeline Research Committee Project PR-3-805
(``A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe''
(December 1989)). These documents are incorporated by reference and are available at
the addresses listed in Sec. 195.3.
(E) An area of general corrosion with a predicted metal loss greater than 50% of
nominal wall.
(F) Predicted metal loss greater than 50% of nominal wall that is located at a crossing
of another pipeline, or is in an area with widespread circumferential corrosion, or is in
an area that could affect a girth weld.
Cenex failed to properly evaluate metal loss anomalies found within HCAs on their Cenex
pipeline. Cenex did not account for the in-line inspection tool’s accuracy with respect to metal
loss. During inspection interviews, Cenex acknowledged that they did not account for the in-line
6



inspection tool’s accuracy when they evaluated which metal loss anomalies required further
investigation. From Cenex’s 2008 metal loss in-line inspection and repair records 40 anomalies
were reviewed by PHMSA. It was found that of those 40 anomalies 4 were found to have had
depths 34% of the nominal wall greater than the reported depths. This indicates that10% of all
anomalies will have a depth 34% of nominal wall greater than their reported depth. Therefore, it
can be assumed that for every 10 anomalies reported as having metal loss equal or greater than
16% of nominal wall one will have a measured metal loss depth of 50% of nominal wall. An
operator must evaluate those metal loss anomalies that are greater than 50% of the nominal wall,
taking the in-line inspection tool’s accuracy into account, to determine if these anomalies are at a
crossing of another pipeline, or in an area with widespread circumferential corrosion, or in an
area that could affect a girth weld. Additionally, an operator must evaluate anomalies using the
in-line inspection tool’s accuracy to determine if they have sufficient remaining strength at the
anomalies. If an operator finds that the metal loss anomaly meets any of these criteria then the
anomaly must be repaired.
9. § 195.505 Qualification program.
Each operator shall have and follow a written qualification program. The program
shall include provisions to:
(b) Ensure through evaluation that individuals performing covered tasks are qualified;
Cenex did not evaluate employees to determine they could recognize and react to task specific
abnormal operating conditions when employees were re-qualified. Pursuant to § 195.505, an
operator’s qualification program must include provisions to ensure that individuals performing
covered tasks are qualified. ‘Qualified’ is defined in § 195.503 as “an individual [that] has been
evaluated and can perform assigned covered tasks and recognize and react to abnormal operating
conditions.” Cenex records show that employees were only evaluated for their ability to
recognize and react to task specific AOCs when they were initially qualified. When employees
were re-qualified they were not re-evaluated for their ability to recognize and react to task
specific AOCs. An operator must ensure that employees are able to recognize and react to task
specific AOCs when they are re-qualified.
10. § 195.573 What must I do to monitor external corrosion control?
(c) Rectifiers and other devices. You must electrically check for proper performance
each device in the first column at the frequency stated in the second column.
Device Check frequency
Rectifier.................................
Reverse current switch
Diode
Interference bond whose failure would
jeopardize structural protection
At least six times each calendar year, but
with intervals not exceeding 2 ½ months
Other interference bond....................... At least once each calendar year, but with
intervals not exceeding 15 months.
7



Cenex failed to electrically check polarization cell replacements (PCRs) at least six times each
calendar year with intervals not exceeding 2 ½ months. Specifically Cenex failed to electrically
check polarization cell replacements recently installed where the Cenex pipeline parallels a wind
farm electrical power transmission line between Fargo and Minot, North Dakota 6 times per year
at intervals not to exceed 2 ½ months. Cenex informed PHMSA that they have only monitored
these PCRs annually. These types of devices are considered to be a form of diode or reverse
current switch in that they allow AC current to pass through them back to the source ground but
they do not allow protective CP current to pass to ground thus minimizing AC interference
currents that could jeopardize structural protection. An operator is required to electrically
inspect devices like reverse current switches, diodes, and interference bonds whose failure could
jeopardize structural protection at least six times each calendar year with intervals not exceeding
2 ½ months.
11. § 195.575 Which facilities must I electrically isolate and what inspections, tests, and
safeguards are required?
(e) If a pipeline is in close proximity to electrical transmission tower footings, ground
cables, or counterpoise, or in other areas where it is reasonable to foresee fault currents
or an unusual risk of lightning, you must protect the pipeline against damage from fault
currents or lightning and take protective measures at insulating devices.
Cenex failed to protect their pipeline against damage from fault currents or lighting. Interviews
with Cenex personnel during the inspection of the Laurel to Billings section of the Cenex
pipeline revealed that there was no fault current protection installed where the Cenex Products
pipeline is in close proximity to a fence around an electrical substation that was located
downstream from the Laurel Refinery. An operator must install ground fault protection where it
is reasonable to foresee fault currents or unusual risk of lightning.
12. § 195.581 Which pipelines must I protect against atmospheric corrosion and what
coating material may I use?
(a) 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…
(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.
Cenex failed to provide protection against atmospheric corrosion for a soil-to-air interface.
Records show that on June 21, 2005 Cenex found that the soil-to-air interface at the Minot
station mainline piping spool, identified as piping item FRS-1000, needed protective coating. On
June 21, 2008, Cenex records show that this same soil-to-air interface still needed protective
coating. Additionally Cenex could not provide evidence that this soil-to-air interface had been
coated at the time of this 2010 inspection, thus establishing that Cenex failed to provide
protection against atmospheric corrosion at its FRS-1000 mainline pipeline spool soil-to-air
8



interface for at least 5 years. An operator is required to provide protection from atmospheric
corrosion at all pipeline soil-to-air interfaces.
13. § 195.583 What must I do to monitor atmospheric corrosion control?
(b) During inspections you must give particular attention to pipe at soil-to-air
interfaces, under thermal insulation, under disbonded coatings, at pipe supports, in
splash zones, at deck penetrations, and in spans over water.
Cenex failed to monitor atmospheric corrosion at several above ground pipe supports located at
the Billings station, Rosebud station, Glendive station, MP 98, MP 193B (Powder River DS
block valve), MP 211B (Yellowstone River DS block valve), and MP 222. These pipe supports
are either made from concrete or they are the type that cannot be easily lowered to ensure
adequate monitoring of atmospheric corrosion between the pipe and the support can be
accomplished. The areas in the vicinity of the supports had rust on the pipe at the interface
between the pipe and the pipe supports that may indicate on-going atmospheric corrosion. An
operator must monitor atmospheric corrosion between above ground pipe and its pipe supports.
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 violations and has recommended that
you be preliminarily assessed a civil penalty of $76,500 as follows:
Item number PENALTY
6 $41,500
12 $35,000
Proposed Compliance Order
With respect to item(s) 1, 2, 3, 4, 5, 7, 8, 9, 10, 11, 12 and 13 pursuant to 49 United States Code
§ 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a
Compliance Order to Cenex. Please refer to the Proposed Compliance Order, which is enclosed
and made a part of this Notice.
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
9



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 5-2012-5013 and for each document
you submit, please provide a copy in electronic format whenever possible.
Sincerely,
Chris Hoidal
Director, Western Region
Pipeline and Hazardous Materials Safety Administration
Enclosures: Proposed Compliance Order
Response Options for Pipeline Operators in Compliance Proceedings
cc: PHP-60 Compliance Registry
PHP-500 G. Davis (#129363, 129364, 129365)
10



PROPOSED COMPLIANCE ORDER
Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety
Administration (PHMSA) proposes to issue to Cenex Pipeline Company a Compliance Order
incorporating the following remedial requirements to ensure the compliance of Cenex Pipeline
Company with the pipeline safety regulations:
1. In regard to Item Number 1 of the Notice pertaining to Cenex’s failure to maintain
a detailed record of the qualification report for weld procedure 110504-1, ensure
the weld qualification report for weld procedure 110504-1 includes; 1) the groove
qualifying test results including the weld tensile strength coupon sizes and the
breaking stress that each tensile strength coupon experienced during testing, nick-
break test results, root bend test results, and face bend test results; and 2) the
sleeve weld qualifying test results including the nick-break test results, the face
bend test results, and the macro test results. Cenex must submit the corrected
record of the weld qualification report for weld procedure 110504-1 to Chris
Hoidal, Director, Western Region.
2. In regard to Item Number 2 of the Notice pertaining to Cenex’s failure to
determine the safe fill height for Minot Tanks 201 and 202, Cenex must ensure
that it has determined the safe fill height for these two tanks and Cenex must take
actions to prevent operation of these tanks above the safe fill height. Cenex must
provide those safe fill heights and documentation confirming actions taken to
prevent operation above those safe fill heights to Chris Hoidal, Director, Western
Region.
3. In regard to Item Number 3 of the Notice pertaining to Cenex’s failure to maintain
current Piping and Instrumentation Diagrams (P&IDs) of the North Dakota
section of the Cenex Products pipeline, Cenex must ensure that its P&IDs for the
North Dakota section of the Cenex Products pipeline includes both the pressure
safety valve tag numbers and the pressure set points associated with those
devices. Cenex must provide those updated P&IDs to Chris Hoidal, Director,
Western Region.
4. In regard to Item Number 4 of the Notice pertaining to Cenex’s failure to maintain
current alignment sheets of its Cenex Products pipeline, Cenex must update their
Cenex Products pipeline alignment sheets to ensure that they show current
pipeline information including but not limited to all crossings of public roads,
railroads, rivers, buried utilities, foreign pipeline crossings and other pipeline
changes as required under 195.404(a). Cenex must provide these updated
alignment sheets to Chris Hoidal, Director, Western Region.
5. In regard to Item Number 5 of the Notice pertaining to Cenex’s failure to maintain
daily discharge pressures of its Billings Tank Farm pump station, Cenex must
provide a pressure recording device at its Billings Tank Farm pump station that
11



will allow them to record the daily discharge pressures of the Billings Tank Farm
pump station and they must ensure that they continuously retain at least 3 years of
those records. Cenex must provide evidence of the installation of the above
pressure recording device and documentation that ensures Cenex will retain
pressure discharge records for this site for at least three years to Chris Hoidal,
Director, Western Region.
6. In regard to Item Number 7 of the Notice pertaining to Cenex’s failure to evaluate
deformation anomalies discovered during the Cenex pipeline 2008 integrity
assessment by taking the in-line inspection tool’s accuracies into account, Cenex
must evaluate the following dent ID#s found during the Glendive Station to Minot
Station in-line inspection: 14000022, 14000048, 14000027, 14000034, 14000051,
14000012, 14000013, 14000023, 14000069, 14000019, 14000076, 14000068,
14000058, and 14000060 and they must evaluate the following dent ID#s found
during the Laurel Station to Billings Station in-line inspection: 14000003,
14000004. If any of these dents are found to be located on the top of the pipeline
or found to affect pipe curvature at a girth weld or a longitudinal seam weld
Cenex must then repair those dents. Cenex must submit records of the above
evaluations and investigations and any subsequent repairs to Chris Hoidal,
Director, Western Region.
7. In regard to Item Number 8 of the Notice pertaining to failure to evaluate some
metal loss anomalies that could reduce their pipeline’s integrity, Cenex must re-
review its ILI metal loss logs taking known data from the 2008 MFL ILI run and
adding the in-line tool accuracy determined by previous 2008 anomaly
investigations. Cenex must then investigate any anomalies that have a potential to
meet the repair criteria under §195.452(h) and if anomalies are found to meet that
criteria Cenex must make appropriate repairs to their pipeline. Cenex must
submit records of the above evaluations and investigations and any subsequent
repairs to Chris Hoidal, Director, Western Region.
8. In regard to Item Number 9 of the Notice pertaining to Cenex’s failure to evaluate
employees ability to recognize and react to task specific abnormal operating
conditions when employees are re-qualified, Cenex must ensure that all
employees are evaluated for their ability to recognize and react to task specific
abnormal operating conditions when they have and are being re-qualified. Cenex
must provide documentation showing that re-qualified employees have been re-
evaluated to recognize and react to task specific abnormal operating conditions to
Chris Hoidal, Director, Western Region.
9. In regard to Item Number 10 of the Notice pertaining to Cenex’s failure to
electrically inspect polarization cell replacements (PCRs) six times each calendar
year with intervals not exceeding 2 ½ months, Cenex must ensure that they
electrically inspect each of their PCRs recently installed where the Cenex pipeline
parallels a wind farm electrical power transmission line between Fargo and Minot,
12



North Dakota six times each calendar year at intervals not exceeding 2 ½ months.
Cenex must provide documentation insuring that these PCRs are electrically
inspected six times each calendar year at intervals not exceeding 6 months to
Chris Hoidal, Director, Western Region.
10. In regard to Item Number 11 of the Notice pertaining to Cenex’s failure to install
ground fault protection at the electrical substation downstream from the Laurel
Refinery, Cenex must install ground fault protection at the electrical substation
downstream from the Laurel Refinery between MP 0.5 and 0.8. Cenex must
provide evidence that ground fault protection has been provided at this location to
Chris Hoidal, Director, Western Region.
12. In regard to Item Number 12 of the Notice pertaining to inadequate coating of the
soil-to-air interface on the Minot station mainline spool, Cenex must provide
coating to the soil-to-air interface on the Minot station mainline spool which is
identified in Cenex atmospheric inspection records as piping item FRS-1000.
Cenex must provide evidence when the coating of this location has been
completed to verify that Cenex has complied with this compliance order item.
13. In regard to Item Number 13 of the Notice pertaining to Cenex’s failure to inspect
for atmospheric corrosion under above ground pipe supports, Cenex must inspect
between the above ground pipe and its associated supports at Billings station,
Rosebud station, Glendive station, MP 98, MP 193B Powder River DS block
valve, MP 211B Yellowstone River DS block valve, and MP 222. Cenex must
take actions to ensure that future inspections will allow inspection for atmospheric
corrosion between above ground pipe and their associated supports at Billings
station, Rosebud station, Glendive station, MP 98, MP 193B Powder River DS
block valve, MP 211B Yellowstone River DS block valve, and MP 222. Cenex
must repair any corrosion that is found during the required atmospheric corrosion
inspections at these above ground pipe support locations. Cenex must provide
evidence that measures have been taken to allow for future atmospheric corrosion
inspections between above ground pipe and associated supports at the above
locations and must provide documentation of atmospheric corrosion inspections
and associated repairs at the above locations to Chris Hoidal, Director, Western
Region.
14. Cenex must complete the above compliance order items within 60 days after
receipt of the Final Order.
15. It is requested (not mandated) that Cenex maintain documentation of the safety
improvement costs associated with fulfilling this Compliance Order and submit
the total to Chris Hoidal, Director, Western 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.
13

520125013_Final Order_12312012_text.pdf

DECEMBER 31, 2012
Mr. John Traeger
President
Cenex Pipeline, LLC
803 Highway 212 South
P.O. Box 909
Laurel, MT 59044-0909
Re: CPF No. 5-2012-5013
Dear Mr. Traeger:
Enclosed please find the Final Order issued in the above-referenced case. It makes findings of
violation, assesses a reduced civil penalty of $41,500, and specifies actions that need to be taken
by Cenex Pipeline, 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, Western 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. Chris Hoidal, Director, Western Region, OPS
Mr. Alan Mayberry, Deputy Associate Administrator for Field Operations, OPS
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 )
)
Cenex Pipeline, LLC, ) CPF No. 5-2012-5013
)
Respondent. )
____________________________________)
FINAL ORDER
Between August 16 and October 29, 2010, 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 Cenex
Pipeline, LLC (Cenex or Respondent), in Montana and North Dakota. Cenex operates
approximately 1200 miles of hazardous liquid pipelines and associated terminals in the U.S.1
The Cenex Products pipeline system that was inspected by PHMSA extends approximately 671
miles from the CHS refinery in Laurel, Montana, to storage facilities in Billings and Glendive,
Montana, and ends in Fargo, North Dakota.2
As a result of the inspection, the Director, Western Region, OPS (Director), issued to
Respondent, by letter dated 
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