# BELLE FOURCHE PIPELINE CO — Notice of Probable Violation

**Citation:** CPF 520095042  
**Type / status:** enforcement / historical  
**Agency:** Pipeline and Hazardous Materials Safety Administration  
**Effective:** Not stated  
**Published:** 2009-12-30

CLOSED notice of probable violation citing 195.402(a), 195.402(c)(12), 195.402(c)(13), 195.404(b)(1), 195.404(c)(3), 195.406(b), 195.412(a), 195.420(b), 195.428(a), 195.428(d), 195.432(b), 195.436, 195.577(a), 195.579(a).

## Document text

Notice of Probable Violation involving BELLE FOURCHE PIPELINE CO. PHMSA's enforcement data identifies the cited regulations as 195.402(a),  195.402(c)(12),  195.402(c)(13),  195.404(b)(1),  195.404(c)(3),  195.406(b),  195.412(a),  195.420(b),  195.428(a),  195.428(d),  195.432(b),  195.436,  195.577(a),  195.579(a). The case was opened on 2009-12-30 and is reported as closed as of 2012-06-26. Proposed civil penalty: $221,200. Assessed civil penalty: $131,900. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

520095042_closure letter_06262012.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520095042/520095042_closure%20letter_06262012.pdf

520095042_closure letter_06262012_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520095042/520095042_closure%20letter_06262012_text.pdf

520095042_Decision on the Petition for Reconsideration_03292012.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520095042/520095042_Decision%20on%20the%20Petition%20for%20Reconsideration_03292012.pdf

520095042_Decision on the Petition for Reconsideration_03292012_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520095042/520095042_Decision%20on%20the%20Petition%20for%20Reconsideration_03292012_text.pdf

520095042_Final Order_11212011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520095042/520095042_Final%20Order_11212011.pdf

520095042_Final Order_11212011_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520095042/520095042_Final%20Order_11212011_text.pdf

520095042_nopv-pcp-pco_12302009.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520095042/520095042_nopv-pcp-pco_12302009.pdf

520095042_nopv-pcp-pco_12302009_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520095042/520095042_nopv-pcp-pco_12302009_text.pdf

520095042_nopv-pcp-pco_12302009_text.pdf

NOTICE OF PROBABLE VIOLATION
PROPOSED CIVIL PENALTY
and
PROPOSED COMPLIANCE ORDER
CERTIFIED MAIL - RETURN RECEIPT REQUESTED
December 30, 2009
Mr. Tad True
Vice President, True Oil
Belle Fourche Pipeline Company
895 W. River Cross Road
P.O. Drawer 2360
Casper, WY 82602
CPF 5-2009-5042
Dear Mr. True:
On August 24-28, 2008, a representative of the Pipeline and Hazardous Materials Safety
Administration (PHMSA), pursuant to Chapter 601 of 49 United States Code, inspected two of
your company’s pipeline systems, the Belle Fourche Pipeline and Sussex Diesel Pipeline in
Casper, Wyoming.
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 violations are:
1. §195.402 Procedural manual for operations, maintenance, and emergencies.
(a) General. Each operator shall prepare and follow for each pipeline system a
manual of written procedures for conducting normal operation and maintenance
activities and handling abnormal operations and emergencies. This manual shall be
reviewed at intervals not exceeding 15 months, but at least once each calendar year,



and appropriate changes made as necessary to insure that the manual is effective.
This manual shall be prepared before initial operations of a pipeline system
commence, and appropriate parts shall be kept at locations where operations and
maintenance activities are conducted.
BFPL records as well as conversations with BFPL personnel showed that the company had
not reviewed or revised its O&M Manual from 2005 to 2008. An operator is required to
perform those reviews and make appropriate changes once each calendar year, but at
intervals not exceeding 15 months.
2. §195.402 Procedural manual for operation, maintenance, and emergencies.
(a) General. Each operator shall prepare and follow for each pipeline system a
manual of written procedures for conducting normal operations and maintenance
activities and handling abnormal operations and emergencies. This manual shall be
reviewed at intervals not exceeding 15 months, but at least once each calendar year,
and appropriate changes made as necessary to insure that the manual is effective.
This manual shall be prepared before initial operations of a pipeline commence, and
appropriate parts shall be kept at locations where operations and maintenance
activities are conducted.
(c) Maintenance and Normal Operations. The manual required by paragraph (a) of
this section must include procedures for the following to provide safety during
maintenance and normal operations:
(12) Establishing and maintaining liaison with fire, police, and other appropriate
public officials to learn the responsibility and resources of each government
organization that may respond to a hazardous liquid or carbon dioxide pipeline
emergency and acquaint the officials with the operator’s ability in responding to a
hazardous liquid or carbon dioxide pipeline emergency and means of communication.
BFPL had not established and maintained liaison with fire, police or other appropriate
public officials along its pipeline system in Wyoming. BFPL’s Public Awareness Program
stated that the company would compile data (names, addresses, phone numbers, etc.)
pertaining to local fire, police, and other emergency and public officials that could be
involved with a response to a hazardous liquid pipeline emergency involving a BFPL
pipeline. However, BFPL had no documentation showing that the company had collected
such data or performed the required liaison activities. BFPL was issued a warning for a
similar citation in CPF 5-2007-5002.
3. §195.402 Procedural manual for operations, maintenance, and emergencies.
(a) General. Each operator shall prepare and follow for each pipeline system a
manual of written procedures for conducting normal operations and maintenance
activities and handling abnormal operations and emergencies. This manual shall be
reviewed at intervals not exceeding 15 months, but at least once each calendar year,
and appropriate changes made as necessary to insure that the manual is effective.
This manual shall be prepared before initial operations of a pipeline commence, and
appropriate parts shall be kept at locations where operations and maintenance
activities are conducted.
2



(c) Maintenance and normal operations. The manual required by paragraph (a) of
this section must include procedures for the following to provide safety during
maintenance and normal operations:
(13) Periodically reviewing the work done by operator to determine the effectiveness
of the procedures used in normal operation and maintenance and taking corrective
action where deficiencies are found.
BFPL had not been periodically reviewing the work completed by its personnel to
determine the effectiveness of their Pipeline Operations and Maintenance Manual (O&M
Manual). BFPL had a procedure for performing such reviews in Section 3.8 of the
“Organization and Responsibilities” section of the BFPL O&M Manual. Nonetheless, the
company had no record of those reviews at the time of the inspection. Section 195.404
requires that an operator maintain a record of each inspection and test required by subpart
F of Part 195 for at least 2 years or until the next inspection or test is performed, whichever
is longer. The absence of any records is a violation of the pipeline safety regulations and
BFPL’s own procedures. It also indicates that the required inspections did not occur,
which is consistent with statements made by the company’s operating personnel at the time
of the inspection.
4. §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;
BFPL did not have a pressure recording device at the Guernsey Pump Station and the
company did not maintain any pressure discharge records for that facility. Each operator is
required to maintain at least 3 years’ worth of records documenting the daily discharge
pressures at each pump station.
5. §195.404 Maps and Records.
(c) Each operator shall maintain the following records for the periods specified;
(3) A record of each inspection and test required by this subpart shall be maintained
for at least 2 years or until the next inspection or test is performed, whichever is
longer.
BFPL’s tank data sheets showed that the Sussex breakout tank received an API Standard
653 out-of-service internal inspection in 2001. However, an inspection report was not in
BFPL’s files or otherwise available for review at the time of the inspection. The operator
is required to keep a complete record of inspections per Section 6 of API 653 until the next
inspection of its type is performed.
6. §195.406 Maximum operating pressure.
(b) No operator may permit the pressure in a pipeline during surges or other
variations from normal operations to exceed 110 percent of the operating pressure
limit established under paragraph (a) of this section. Each operator must provide
adequate controls and protective equipment to control the pressure within this limit.
3



BFPL had no safety device(s) installed at the Guernsey Pump Station to prevent
overpressuring of the pumping equipment and piping installed at that facility or of the
pipeline located downstream from that station. Each pipeline operator must provide
adequate controls and protective equipment to control the pressure within the maximum
operating pressure (MOP) during normal operations and 110% of MOP during abnormal
operations.
7. §195.412 Inspection of rights-of-way and crossings under navigable waters.
(a) Each operator shall, at intervals not exceeding 3 weeks, but at least 26 times each
calendar year, inspect the surface conditions on or adjacent to each pipeline right-of-
way. Methods of inspection include walking, driving, flying or other appropriate
mean of traversing the right-of-way.
BFPL did not inspect its pipeline right-of-way at the appropriate time intervals for the
Montana portion of the Bicentennial Line. The evidence shows that the required interval
was exceeded between March 24 and April 21, 2008, and between June 4 and July 5, 2008.
BFPL had records of over-flights occurring between these dates, but those records indicate
that the Montana portion of the Bicentennial line was not over-flown. In addition, the
recordkeeping process for right-of-way inspections made it difficult for BFPL to keep
track of inspection intervals for the various segments of its pipeline system, thereby
increasing the probability that a right-of-way inspection could be missed. An operator is
required to patrol all of their pipelines at an interval not exceeding 3 weeks but at least 26
times per year and to maintain a record of those patrols.
8. §195.420 Valve maintenance.
(b) Each operator shall, at intervals not exceeding 7 1/2 months, but at least twice
each calendar year, inspect each mainline valve to determine that it is functioning
properly.
BFPL failed to inspect numerous mainline valves at the required frequency from 2006 to
2007. BFPL records confirm the following 25 mainline valves were not inspected twice
during the 2006 calendar year:
Area Valve Designation Area Valve Designation
Shilight/Kaye 010-011 Donkey Creek 010-002
Shilight/Kaye 015-005 Donkey Creek 010-003
Shilight/Kaye 015-004 Donkey Creek 010-001
Shilight/Kaye 015-005 Donkey Creek 010-101
Shilight/Kaye 015-002 Sussex Products 069-0001
Shilight/Kaye Poison Draw 6” Tie In Sussex Products 069-0006 (6”)
Shilight/Kaye Poison Draw Line 8” Sussex Products 069-0006 (4”)
Shilight/Kaye 010-0056 Sussex Products 069-0007 (6”)
4



Shilight/Kaye 101-006 Sussex Products 069-0007 (4”)
Shilight/Kaye 015-001 Sussex Products 069-0008
Shilight/Kaye 015-011
Shilight/Kaye 015-012
Shilight/Kaye 101-008
Shilight/Kaye 101-009
Shilight/Kaye 010-010
In addition, BFPL records show that inspections for the following 22 mainline valves
exceeded the 7 ½ month maximum inspection interval:
Valve Designation Period Days in excess
of 7 ½ months
010-001 June 1, 2006 to January 14, 2007 2
010-101 June 1, 2006 to January 14, 2007 2
015-002 June 7, 2006 to January 25, 2007 7
6” Tie In June 7, 2006 to January 25, 2007 7
8” Poison Draw Line June 7, 2006 to January 25, 2007 7
010-005 June 7, 2006 to January 25, 2007 7
010-006 June 7, 2006 to January 25, 2007 7
015-001 June 8, 2006 to January 25, 2007 6
010-008 May 23, 2006 to January 22, 2007 19
010-009 May 23, 2006 to January 22, 2007 19
010-010 May 23, 2006 to January 22, 2007 19
069-0001 April 20, 2006 to January 11, 2007 41
069-0003 October 8, 2006 to July 13, 2007 53
Incoming Trap October 8, 2006 to July 13, 2007 53
069-0004 March 2, 2006 to December 17, 2006 65
Outgoing Launcher March 2, 2006 to December 17, 2006 65
069-0005 March 2, 2006 to December 17, 2006 65
5



069-0007 April 10, 2006 to January 9, 2007 49
Iberline Incoming Trap April 10, 2006 to January 9, 2007 49
069-0007 April 10, 2006 to January 9, 2007 49
Iberline Outgoing Launcher April 10, 2006 to January 9, 2007 49
069-0008 April 10, 2006 to January 4, 2007 44
Each operator must inspect each mainline valve at least twice each calendar year at
intervals not exceeding 7 ½ months and maintain records of such inspections for at least 2
years.
9. §195.428 Overpressure safety devices and overfill protection systems.
(a) Except as provided in paragraph (b) of this section, each operator shall, at
intervals not exceeding 15 months, but at least once each calendar year, or in the case
of pipelines used to carry highly volatile liquids, at intervals not to exceed 7 ½
months, but at least twice each calendar year, inspect and test each pressure limiting
device, relief valve, pressure regulator, or other item of pressure control equipment to
determine that it is functioning properly, is in good mechanical condition, and is
adequate from the standpoint of capacity and reliability of operation for the service
in which it is used.
BFPL records established that a number of its pressure limiting devices were not inspected
and tested at the required frequency between the years 2006 to 2008. An operator is
required to inspect and test each item of pressure control equipment once each calendar
year not to exceed 15 months.
• Donkey Creek and Hwy 450 stations pressure controls were not tested and inspected in
the 2007 calendar year. Additionally, BFPL exceeded the 15-month interval for testing
and inspecting pressure controls at these stations by 68 and 98 days, respectively.
• Seiler station pressure controls exceeded the 15-month interval for testing and inspecting
in the 2007 calendar year by 120 days.
• At the time of this inspection, BFPL had not yet tested and inspected Sussex pump
station and Guernsey terminal for the 2008 calendar year, resulting in BFPL exceeding
the 15-month interval by a minimum of 145 and 105 days, respectively.
10. §195.428 Overpressure safety devices and overfill protection systems
(a) Except as provided in paragraph (b) of this section, each operator shall, at
intervals not exceeding 15 months, but at least once each calendar year, or in the case
of pipelines used to carry highly volatile liquids, at intervals not to exceed 7 ½
months, but at least twice each calendar year, inspect and test each pressure limiting
device, relief valve, pressure regulator, or other item of pressure control equipment to
determine that it is functioning properly, is in good mechanical condition, and is
adequate from the standpoint of capacity and reliability of operation for the service
in which it is used.
6



(d) After October 2, 2000, the requirements of paragraphs (a) and (b) of this section
for inspection and testing of pressure control equipment apply to the inspection and
testing of overfill protection systems.
Conversations with BFPL personnel confirmed that the high-level alarms on the following
three breakout tanks associated with the Sussex Diesel Line had never been tested at the
prescribed intervals
▪ Sussex Pump Station Breakout Tank
▪ Davis Station (Tank 74) Breakout Tank
▪ Hawk Point Terminal Breakout Tank
Each operator must inspect and test overfill protection system on each breakout tank at
least once each calendar year at intervals not to exceed 15 months, and maintain records of
those inspections and tests for at least two years.
11. §195.432 Inspection of in-service breakout tanks.
(a) Except for breakout tanks inspected under paragraphs (b) and (c) of this section,
each operator shall, at intervals not exceeding 15 months, but at least each calendar
year, inspect each in-service breakout tank.
(b) Each operator shall inspect the physical integrity of in-service atmospheric and
low pressure steel aboveground breakout tanks according to section 4 of API
Standard 653. 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).
BFPL’s tank data sheets verified that BFPL had never performed an External Tank
Inspection on the Sussex Breakout Tank. Because it appears this tank received an internal
inspection in 2001 this tank should have received an external inspection no later than 2006,
as well as the 5-year interval prescribed in API 653 Section 6.3.2.
12. §195.436 Security of facilities.
Each operator shall provide protection for each pumping station and breakout tank
area and other exposed facility (such as scraper traps) from vandalism and
unauthorized entry.
BFPL had no security fencing installed around the Donkey Creek Pump Station. Also 4.5
to 5 foot high security fencing around the Sussex Pump Station and Sussex Breakout Tank
was only made of 4 foot high 6 inch grid woven steel wire with 2 strands of barbed wire
above it. This type of fence will keep livestock out of the facility but it is not adequate to
prevent vandalism and unauthorized entry to the facility.
13. §195.577 What must I do to alleviate interference currents?
(a) For pipelines exposed to stray currents, you must have a program to identify, test
for, and minimize the detrimental effects of such currents.
BFPL’s cathodic protection monitoring records for the 12” Donkey Creek Pipeline in the
area in and around Guernsey station and Ft Laramie station for the 2006 calendar year
showed several test stations with high off levels. High off levels indicate that cathodic
7



protection interference currents may be adversely affecting a pipeline. Nonetheless, at the
time of the inspection, BFPL had not taken the appropriate steps to perform an interference
study to determine if there were interference currents on their pipeline or to mitigate any of
the interference currents that might exist. The Pipeline Safety Regulations require an
operator to identify, test for, and minimize the detrimental effects of stray currents.
14. §195.579 What must I do to mitigate internal corrosion?
(a) General. If you transport any hazardous liquid or carbon dioxide that would
corrode the pipeline, you must investigate the corrosive effect of the hazardous liquid
or carbon dioxide on the pipeline and take adequate steps to mitigate internal
corrosion.
Since 2006, BFPL has experienced at least three leaks due to internal corrosion, a
condition that may be the result of the corrosive effects of the crude oil that is being
shipped through its pipeline system. The Pipeline Safety Regulations require an operator
who transports a hazardous liquid that could corrode a pipe to investigate and take
adequate steps to mitigate that condition. Nonetheless, at the time of the inspection, BFPL
had not conducted such an investigation or taken any steps to mitigate that condition.
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 $221,200 as follows:
Item Number PENALTY
1 $37,100
5 $17,100
8 $30,800
9 $62,100
10 $30,800
11 $43,300
Warning Items
With respect to items 7 and, 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 Belle Fourche Pipeline Company being subject to additional
enforcement action.
8



Proposed Compliance Order
With respect to items 2, 3, 4, 6, 10, 11, 12, 13, and 14 pursuant to 49 United States Code § 60118,
the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order
to Belle Fourche Pipeline Company. 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 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 5-2009-5042 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 (#120773)
9



PROPOSED COMPLIANCE ORDER
Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety
Administration (PHMSA) proposes to issue to Belle Fourche Pipeline Company (BFPL) a
Compliance Order incorporating the following remedial requirements to ensure the compliance of
BFPL with the pipeline safety regulations:
1. In regard to Item Number 2 of the Notice pertaining to the lack of the development of a list
of local fire, police, and other emergency and public officials:
BFPL must develop a list of local fire, police, and other emergency and public officials
that could potentially respond to an emergency associated with BFPL's hazardous liquid
pipelines in Wyoming. BFPL must then conduct periodic liaison activities with these
entities to .accomplish the following:
• Learn the responsibilities and resources of each entity.
• Acquaint each agency with BFPL's ability in responding to a hazardous liquid pipeline
emergency.
• Understand the means of communication that could be used between BFPL and each
entity in the event of a pipeline emergency.
2. In regard to Item Number 3 of the Notice pertaining to BFPL not reviewing the work done
by its personnel to determine the effectiveness of procedures:
BFPL must review the work done by its employees to determine the effectiveness of their
procedure and they must document such reviews.
3. In regard to Item Number 4 of the Notice pertaining to the lack of a pressure recording
device at the Guernsey Pump Station:
BFPL must install a pressure recording device at the Guernsey Pump Station to record the
discharge pressure of the station. BFPL must then retain the pressure records for a
minimum of three years.
4. In regard to Item Number 6 of the Notice pertaining to the lack of a safety device that
prevents overpressuring of pumping equipment at the Guernsey Pump Station:
BFPL must install an overpressure protection device at the Guernsey Pump Station that
prevents the Maximum Operating Pressure (MOP) of the piping at the station and the
pipeline downstream from the station from being exceeded.
5. In regard to Item Number 10 of the Notice pertaining to the lack of inspection and testing
of high level alarms on three breakout tanks on the Sussex Diesel Line:
BFPL must inspect and test the high level alarms on the following tanks:
▪ Sussex Pump Station Breakout Tank (BOT)
▪ Davis Station (Tank 74) BOT
▪ Hawk Point Terminal BOT
6. In regard to Item Number 11 of the Notice pertaining to exceeding the maximum interval
of 5 years for an API Standard 653 External Inspection of the Sussex diesel BOT:
BFPL must conduct an API Standard 653 External Inspection on their Sussex diesel BOT.
10



7. In regard to Item Number 12 of the Notice pertaining to the lack of security fencing around
the Donkey Creek Pump Station and the inadequate security fencing around the Sussex
Pump Station and Sussex BOT:
BFPL must install security fencing around the Donkey Creek Pump Station that is a
minimum of six feet high and includes a minimum of 3 strands of barbed wire above the
fencing. Appropriate warning signs and operator contact information must be installed on
the fencing and all gates must be adequately locked.
In addition, BFPL must replace the security fencing around the Sussex Pump Station and
Sussex Breakout Tank with security fencing that is a minimum of six feet high and
includes a minimum of 3 strands of barbed wire above the fencing. Appropriate warning
signs and operator contact information must be installed on the fencing and all gates must
be adequately locked.
8. In regard to Item Number 13 of the Notice pertaining to High "Off' CP levels on the 12"
Donkey Creek Pipeline located between Guernsey station and Ft Laramie station:
BFPL must perform an interference study on the Donkey Creek Pipeline between
Guernsey station and Ft Laramie station and remediate any stray currents that are found.
9. In regard to Item Number 14 of the Notice pertaining to potentially corrosive crude oil
being shipped through the Belle Fourche Pipeline System may be causing internal
corrosion of the pipeline system:
BFPL must conduct an investigation to determine if crude oil being shipped through their
pipeline system is causing internal corrosion. If the investigation determines that the crude
oil is in fact causing internal corrosion, BFPL must take appropriate remedial actions to
prevent internal corrosion from continuing to occur in their pipeline system.
10. BFPL must complete the items described above within 60 days of receipt of the Final
Order.
11. Belle Fourche Pipeline Company shall 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. 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.
11

520095042_Decision on the Petition for Reconsideration_03292012_text.pdf

MAR 29 2012
Mr. Tad True
Vice President
Belle Fourche Pipeline Company
P.O. Box 2360
Casper, WY 82602
Re: CPF No. 5-2009-5042
Dear Mr. True:
Enclosed please find the decision on the petition for reconsideration filed by Belle Fourche
Pipeline Company in the above-referenced case. For the reasons set forth in the decision,
your petition to withdraw the findings of violation in Items 13 and 14 of the Final Order is
denied. In addition, your petition to withdraw the terms of the compliance order associated
with Item 14 is denied. Your petition to find that Belle Fourche has satisfied the terms of the
compliance order associated with Item 13 is granted. Service of this document by certified
mail is complete upon mailing as 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. Alan Mayberry, Deputy Associate Administrator for Field Operations, OPS
Mr. Chris Hoidal, Director, Western Region, OPS
Mr. Colin Harris, Holme Roberts & Owen LLP
1801 13th Street, Suite 300, Boulder, CO 80302-5259
CERTIFIED MAIL – RETURN RECEIPT REQUESTED [71791000164203446319]



U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, D.C. 20590
____________________________________
In the Matter of )
Belle Fourche Pipeline Company, ) CPF No. 5-2009-5042
)
)
)
Petitioner. )
____________________________________)
DECISION ON PETITION FOR RECONSIDERATION
On November 21, 2011, pursuant to 49 U.S.C. §§ 60118 and 60122, the Pipeline and Hazardous
Materials Safety Administration (PHMSA) issued a Final Order in this proceeding finding that
Belle Fourche Pipeline Company (BFPL or Petitioner) committed nine violations of the pipeline
safety regulations in 49 C.F.R. Part 195. The Final Order assessed a civil penalty of $131,900
for four of the violations and ordered BFPL to take certain corrective measures (Compliance
Order). BFPL operates approximately 600 miles of pipeline in Montana, North Dakota, and
Wyoming transporting crude oil and refined petroleum products.1
BFPL submitted a Petition for Reconsideration of the Final Order dated December 9, 2011
(Petition). In its Petition, BFPL requested reconsideration of Items 13 and 14 in the Final Order,
which had found that BFPL violated 49 C.F.R. §§ 195.577(a) and 195.579(a), respectively.
Petitioner also requested a stay of the terms of the Compliance Order associated with those items
pending the issuance of a decision on its Petition. PHMSA granted the stay on
2
January 13, 2012.
Pursuant to 49 C.F.R. § 190.215, a respondent may petition for reconsideration of a final order
that has been issued pursuant to § 190.213. Section 190.215 provides that PHMSA does not
consider repetitious information or arguments, but 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
as deemed appropriate.
1 This information is reported by BFPL as required by 49 C.F.R. § 195.49. On its website, the company states that
it operates 1,500 miles of pipeline. http://www.truecos.com/BFPL (last accessed Mar. 8, 2012).
2 The Final Order did not assess civil penalties for Items 13 and 14. On December 19, 2011, BFPL submitted
payment in full of the civil penalties assessed in the Final Order for Items 8, 9, 10, 11.



2
Item 13: The Final Order determined that BFPL violated 49 C.F.R. § 195.577(a), which states:
§ 195.577 What must I do to alleviate interference currents?
(a) For pipelines exposed to stray currents, you must have a program
to identify, test for, and minimize the detrimental effects of such currents.
The Final Order determined that BFPL failed to have and implement a program to identify, test
for, and minimize the detrimental effects of stray currents on the company’s pipeline. As stated
in the Order, the operator’s cathodic protection survey records from January 2006 to December
2008 showed there were areas on its pipeline with high “off” levels, indicative of interference
currents that could have an adverse effect on the pipeline. BFPL could not produce a
documented interference study or any other evidence to demonstrate the company took action in
accordance with § 195.577(a) to test the interference currents that were detected during the
surveys to determine whether any effects were adverse to the pipeline and to mitigate detrimental
effects.
In its Petition, BFPL acknowledged that § 195.577(a) requires companies to identify, test for,
and minimize the detrimental effects of electrical current flowing from an external source to the
affected pipeline.
company argued that there was insufficient evidence of a violation presented by OPS, and that
the evidence of compliance presented by BFPL was not properly considered.
3 Petitioner disagreed, however, that BFPL violated this requirement. The
First, BFPL argued that the finding of violation was in error because the evidence presented by
OPS did not support the finding. Specifically, Petitioner stated that the cathodic protection
survey records from 2006 to 2008 were not sufficient evidence to prove a violation.
4
As noted in the Final Order, BFPL’s survey records from 2006-2008 indicated that its pipeline
was exposed to interference currents. Under § 195.577(a), the company was required to identify,
test for, and minimize the detrimental effects of those stray currents. Despite the indications of
interference currents, BFPL did not produce any evidence to demonstrate that it had taken action
during the time period in question to conduct tests to determine whether the interference currents
were adversely affecting the pipeline.5 These facts constituted sufficient evidence for PHMSA
to find that BFPL violated § 195.577(a).
Second, Petitioner argued that the company’s survey records from 2006-2008 demonstrated that
the company did, in fact, have a program to identify and test for interference currents. Petitioner
stated “[t]he whole purpose of the surveys” was to identify and test for interference currents,
citing testimony it offered at the hearing.6
Petitioner claimed that this evidence was not
addressed in the Order.
3 Petition at 2.
4 Petition at 2.
5 BFPL conducted a close interval survey in July 2009, but as stated in the Final Order, the survey was performed
after the OPS inspection, and therefore did not demonstrate compliance for the time period in question.
6 Petition at 3.



3
The Final Order specifically addressed this position taken by the operator and the evidence it
offered in support. For example, the Final Order noted that “BFPL claimed the reports used by
PHMSA in support of the allegation demonstrated this program was in place and implemented.”7
While the survey report records showed Petitioner could apparently detect interference currents
on its pipeline, the Order concluded that the records themselves did not demonstrate compliance
with § 195.577(a) because, among other things, BFPL never actually tested the interference
currents during the time period in question to determine if they were detrimental.8
BFPL argued in its Petition that it was not necessary for the company to test the interference
currents because testimony in the record “unarguably shows” that the interference currents were
not detrimental to the pipeline.
9 Petitioner cited a statement by its witness that the pipelines in
the area are all tied together with either piping, electrical grounding, or bonds. Petitioner argued
there was no need to conduct additional tests or mitigation “because any issues had already been
mitigated.”10 Petitioner claimed this evidence was not acknowledged or refuted in the Order.
The Final Order specifically discussed BFPL’s claim that it knew the source of the current and
that it was not detrimental.
11 The Order quoted the company’s own Brief, which recited the
testimony of its witness that the pipelines in the area “are tied together with either piping,
Final Order determined, however, that the company’s assumption that interference currents were
not detrimental was not an excuse for failing to conduct the testing required under the regulation.
BFPL provided no evidence that it performed an analysis during the time period in question to
confirm that interference currents were not detrimental to the pipeline.
electrical grounding between the different pipeline companies in the area, or by bonds.”12 The
Lastly, Petitioner argued that it was improper for the Final Order to include a statement that
BFPL failed to follow written procedures for determining if the stray currents had detrimental
effects. Petitioner claimed the issue of “written procedures” was never raised at the hearing.
13
The Notice of Probable Violation provided sufficient notice to BFPL that the company had
allegedly violated the requirement in § 195.577(a) to identify, test for, and minimize the
detrimental effects of interference currents.
14
Whether or not BFPL had adequate written
procedures in place for these activities, the company violated § 195.577(a) by failing to test the
interference currents to determine if they were detrimental to the pipeline facility.
7 Final Order at 16.
8 Although Petitioner is correct that the testimony it offered on this point was not quoted in the Order, the testimony
only repeated the claim advanced by the company, namely that “[t]he survey reports used by [PHMSA] inspectors . .
. is conclusive evidence that Belle Fourche implements this program.” BFPL’s Hearing Exhibit 10 at ¶3.
9 Petition at 3.
10 Petition at 3.
11 Final Order at 15.
12 Final Order at 15, (quoting BFPL’s Post-hearing Brief at 22 (Oct. 11, 2010), which cited Hearing Ex. 10 at ¶4).
13 Petition at 4. See also Final Order at 16. Petitioner submitted copies of its written procedures.
14 Petitioner’ program under § 195.577 must be in writing in accordance with § 195.402(c)(3).



4
For the above reasons, I confirm that BFPL committed a violation of § 195.577(a). BFPL’s
petition to withdraw the finding of violation for Item 13 is denied.
In its Petition, BFPL argued that the close interval survey (CIS) it performed in July 2009 should
be found to have satisfied the terms of the Compliance Order associated with Item 13.
15 In its
post-hearing submission, OPS “agree[d] that the performance of that CIS renders the proposed
further action to remediate this compliance item. BFPL’s request that PHMSA find it has
compliance order unnecessary.”16 For these reasons, I find there is no need for BFPL to take
satisfied the compliance terms associated with Item 13 is granted.
Item 14: The Final Order determined that BFPL violated 49 C.F.R. § 195.579(a), which states:
§ 195.579 What must I do to mitigate internal corrosion?
(a) General. If you transport any hazardous liquid or carbon dioxide
that would corrode the pipeline, you must investigate the corrosive effect
of the hazardous liquid or carbon dioxide on the pipeline and take
adequate steps to mitigate internal corrosion.
The Final Order found that BFPL had failed to investigate the corrosive effect of the hazardous
liquid it transported and to take adequate steps to mitigate internal corrosion. As stated in the
Order, BFPL’s pipeline system experienced at least three pipeline leaks between 2006 and 2008
that were caused by internal corrosion, but the company never investigated the corrosive effect
of the product or mitigated the internal corrosion.
In its Petition, BFPL did not disagree that the company never investigated the corrosive effect of
the product or mitigated internal corrosion. Petitioner argued, however, the regulation did not
require the company to conduct an investigation in the first place. Petitioner stated that the
regulation “does not impose an absolute obligation” on all operators to conduct an internal
corrosion study, but only in cases where “such liquid ‘would’ corrode the pipeline” is an
regulation in a way that requires the company to conduct an internal corrosion study irrespective
used guidance to broaden the regulatory requirement beyond the text of the regulation.
investigation required.17 Petitioner claimed the Final Order was erroneous in applying the
of the nature of the liquids transported. Petitioner also argued the Final Order impermissibly
After reviewing the Final Order, I find PHMSA applied § 195.579(a) in a manner that is
consistent with the text of the regulation. Section 195.579(a) establishes a duty for operators to
investigate and mitigate internal corrosion whenever the product would corrode the pipeline.
Petitioner’s pipeline system experienced a series of accidents caused by internal corrosion—
evidence the product transported “would corrode the pipeline.”18
Despite the information that
product was actually causing internal corrosion, BFPL failed to investigate and mitigate the
15 Petition at 6-7.
16 OPS Post-Hearing Submittal at 10 (Nov. 12, 2010).
17 Petition at 5.
18 § 195.579(a).



5
internal corrosion. BFPL’s failure to investigate and take steps to mitigate the internal corrosion
support the agency’s conclusion that the company violated the requirements in § 195.579(a).
The agency’s conclusion was based on application of the regulation to the facts of the case.
19
Reference to an Advisory Bulletin in the Final Order was merely ancillary. For example, the
Order cited to an Advisory Bulletin issued by the agency in 2008 to explain why BFPL’s
purported interpretation of the regulation was erroneous. BFPL had claimed the regulation
requires prior “knowledge or reasonable belief” that product would corrode the pipeline before
triggering the investigation requirements in § 195.579(a). Based on that interpretation, the
company had argued it was never obligated to conduct an investigation.
20
To explain why that interpretation is incorrect, the Final Order cited to the advisory, which was
issued to remind operators of their responsibilities to identify circumstances under which the
potential for internal corrosion must be investigated. In particular, the advisory noted that
§ 195.579(a) requires operators “to determine if the hazardous liquids they are transporting could
corrode the pipeline and, if so, take adequate steps to mitigate that corrosion potential.”21 The
document cautioned operators that even though “the base commodity may not be corrosive, all
hazardous liquids regulated under part 195 could be corrosive during some phase of the
production and/or manufacturing process when contaminants could be introduced.” The
advisory was consistent with statements made by the agency in the preamble to the original
rulemaking.
preamble, nor the advisory conveyed that operators must first have knowledge or reasonable
belief that a product would corrode the pipeline before triggering § 195.579(a).
22 Contrary to the interpretation advanced by BFPL, neither the regulation, its
Petitioner cited two court decisions that it claimed supported the position that an agency may not
rely on interpretive guidance to expand a regulation without going through notice and
comment.23 Since the finding of violation was not based on the advisory or interpretive
guidance, the two decisions cited by Petitioner are inapplicable.
24
19 See Final Order at 18 (finding that “[g]iven the pipeline failures caused by internal corrosion, BFPL was required
under§ 195.579(a) to investigate the corrosive effects of the hazardous liquid transported in its pipeline system.”).
20 Brief at 24 (stating “there must be some type of prior knowledge or reasonable belief, based on the
circumstances, that the hazardous liquid would corrode the pipeline.”); see also Final Order at 17.
21 Proper Identification of Internal Corrosion Risk, 73 Fed. Reg. 71,089 (Nov. 24, 2008).
22 Controlling Corrosion on Hazardous Liquid and Carbon Dioxide Pipelines, 66 Fed. Reg. 66,994, 67,000 (Dec. 27,
2001) (stating the rule “requires operators to investigate the effects of transporting hazardous liquid or carbon
dioxide which could corrode the pipeline, and take adequate steps to mitigate corrosion.”).
23 Petition at 5, citing Natural Resources Defense Council v. EPA, 643 F.3d 311, 321 (D.C. Cir. 2011); and National
Mining Ass’n v. Jackson, 768 F.Supp.2d 34, 49 (D.D.C. 2011).
24 Agencies may issue regulatory interpretations in accordance with 5 U.S.C. § 553(b)(A). An “administrative
interpretation . . . becomes of controlling weight unless it is plainly erroneous or inconsistent with the regulation.”
Bowles v. Seminole Rock & Sand Co., 325 U.S. 410 (1945).



6
In addition to the above legal arguments, Petitioner maintained that as a factual matter the
internal corrosion leaks experienced on the BFPL pipeline system were not sufficient evidence to
establish that the product transported would corrode the pipeline. Petitioner made this same
argument prior to issuance of the Final Order, claiming the leaks were disconnected in time,
location, operations, and type of crude.25
The Final Order has already determined that BFPL “may not ignore information about [the]
internal corrosion leaks on its pipeline merely because it does not consider the leaks to be related
in time or location. Likewise, the fact that leaks occurred on idle lines or dead legs is no excuse
to imagine stronger evidence that an operator must take action under § 195.579(a) than the
not to investigate the corrosive effects.”26 I find no reason to alter that determination. It is hard
occurrence of multiple leaks on its pipeline system that were caused by internal corrosion.
Finally, Petitioner maintained there was no evidence in the record that the leaks resulted from
corrosion caused by “the specific type of liquid transported” by BFPL.27 I find no support in the
record for Petitioner’s assertion. The company’s own records indicate that the leaks were caused
by internal corrosion. As noted in the Final Order, even if an operator believes the commodity it
transports is not normally corrosive, contaminants may be introduced during upset conditions
when untreated corrosive materials may bypass the treatment process and enter the pipeline.
28
For the above reasons, I confirm that BFPL committed a violation of § 195.579(a). BFPL’s
petitions to withdraw the finding of violation and associated compliance terms for Item 14 are
denied.
The stay granted on January 13, 2012, is hereby lifted. Petitioner must complete the actions
required by the Compliance Order associated with Item 14 (paragraph 4 on page 26 of the Final
Order) and submit documentation demonstrating compliance, as set forth therein, within 60 days
of the date of this Decision. Except as specified above for Item 13, all other terms of the Final
Order remain in effect and are not modified by this Decision.
This Decision on Reconsideration is the final administrative action in this proceeding.
___________________________________ ____________________
Jeffrey D. Wiese Date Issued
Associate Administrator
for Pipeline Safety
25 Brief at 24-25.
26 Final Order at 18.
27 Petition at 6.
28 Final Order at 18.

520095042_closure letter_06262012_text.pdf

CERTIFIED MAIL - RETURN RECEIPT REQUESTED
June 26, 2012
Mr. Tad True
Vice President
Belle Fourche Pipeline Company
455 North Popular
Casper, WY 82601
CPF 5-2009-5042
Dear Mr. True:
On November 21, 2011, the Pipeline and Hazardous Materials Safety Administration
(PHMSA) issued to Belle Fourche Pipeline Company a Final Order in the above-referenced
case. This Order included a Compliance Order and Civil Penalty assessment. Based on our
review of the documentation you provided and confirmation of payment of the civil penalty,
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 G. Davis (#120773)

520095042_Final Order_11212011_text.pdf

NOV 21 2011
Mr. Tad True
Vice President
Belle Fourche Pipeline Company
455 North Popular
Casper, WY 82601
Re: CPF No. 5-2009-5042
Dear Mr. True:
Enclosed please find the Final Order issued in the above-referenced case. It makes findings of
violation, withdraws several allegations, assesses a reduced civil penalty of $131,900, and
specifies actions that must be taken by Belle Fourche 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. Alan Mayberry, Deputy Associate Administrator for Field Operations, Pipeline Safety
Mr. Chris Hoidal, Director, Western Region, PHMSA
Mr. Colin Harris, Holme Roberts & Owen LLP
1801 13th Street, Suite 300, Boulder, CO 80302-5259
CERTIFIED MAIL – RETURN RECEIPT REQUESTED [71791000164202826396]



U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, D.C. 20590
____________________________________
In the Matter of )
Belle Fourche Pipeline Company, ) CPF No. 5-2009-5042
)
)
)
Respondent. )
____________________________________)
FINAL ORDER
On August 24 through 28, 2008, 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 Belle Fourche
Pipeline Company (BFPL or Respondent) in Casper, Wyoming. Belle Fourche operates
approximately 600 miles of pipeline in Montana, North Dakota, and Wyoming transporting
crude oil and refined petroleum products.
1
As a result of the inspection, the Director, Western Region, PHMSA (Director), issued to
Respondent, by letter dated December 30, 2009, 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 Respondent had committed 13 violations of 49 C.F.R. Part 195 and
proposed a civil penalty of $221,200 for the alleged violations. The Notice also proposed to
order that Respondent take certain measures to correct the alleged violations.
BFPL responded to the Notice by letters dated February 19 and August 30, 2010 (collectively,
Response). The company contested several of the allegations and requested a hearing. In
accordance with 49 C.F.R. § 190.211, a hearing was held on September 9, 2010, in Lakewood,
Colorado, with an attorney from the Office of Chief Counsel, PHMSA, presiding. After the
hearing, Respondent provided additional written material for the record by letter dated October
11, 2010 (Brief).
FINDINGS OF VIOLATION
The Notice alleged that Respondent committed violations of 49 C.F.R. Part 195, as follows:
Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 195.402(a), which states:
1 This information is reported by Respondent pursuant to 49 C.F.R. § 195.49.



2
§ 195.402 Procedural manual for operations, maintenance, and
emergencies.
(a) General. Each operator shall prepare and follow for each pipeline
system a manual of written procedures for conducting normal operations
and maintenance activities and handling abnormal operations and
emergencies. This manual shall be reviewed at intervals not exceeding 15
months, but at least once each calendar year, and appropriate changes
made as necessary to insure that the manual is effective. This manual
shall be prepared before initial operations of a pipeline system commence,
and appropriate parts shall be kept at locations where operations and
maintenance activities are conducted.
The Notice alleged that Respondent violated § 195.402(a) by failing to review or revise its
operations and maintenance (O&M) manual at least once each calendar year from 2005 to 2008.
BFPL’s O&M manual obtained during the PHMSA inspection in August 2008 was dated
February 2005 and stamped “Rev. 1.0,” suggesting the company had not revised the document
since 2005. Respondent’s compliance coordinator stated during the inspection that BFPL had
not reviewed or revised the O&M manual since 2005.2
At the hearing, Respondent explained that the revision number and date on the O&M manual
were oversights and that statements by the employee during the agency’s inspection were
misinformed and erroneous. Respondent presented a witness who testified that he had personally
performed annual reviews of BFPL’s O&M manual in accordance with § 195.402(a) since 2006.
Respondent also introduced completed “Revision Request Forms,” which show that annual
reviews were performed, and as a result of those reviews, that certain determinations were made
to revise the procedures.3
The Director stated at the hearing that he recommended withdrawing Item 1 based on the
company’s assertions and submissions. For this reason, Respondent provided no additional
information regarding Item 1 in its post-hearing Brief.4
After considering all of the evidence and the explanation provided by BFPL that the company
conducted annual reviews and made revisions to its O&M manual during the period in question,
the Director has recommended this allegation of violation be withdrawn. Accordingly, I am
withdrawing this allegation of violation.
Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 195.402(a) and (c)(12), which
state:
§ 195.402 Procedural manual for operations, maintenance, and
emergencies.
(a) General. Each operator shall prepare and follow for each pipeline
system a manual of written procedures for conducting normal operations
2 Violation Report at 3.
3 Respondent Hearing Exhibit 11.
4 Brief at 2.



3
and maintenance activities and handling abnormal operations and
emergencies . . . .
(c) Maintenance and normal operations. The manual required by
paragraph (a) of this section must include procedures for the following to
provide safety during maintenance and normal operations: . . .
(12) Establishing and maintaining liaison with fire, police, and other
appropriate public officials to learn the responsibility and resources of
each government organization that may respond to a hazardous liquid or
carbon dioxide pipeline emergency and acquaint the officials with the
operator’s ability in responding to a hazardous liquid or carbon dioxide
pipeline emergency and means of communication.
The Notice alleged that Respondent violated § 195.402(a) and (c)(12) by failing to follow the
company’s written procedures for liaison with fire, police, and other appropriate public officials.
Specifically, the Notice alleged that BFPL’s written procedures for public awareness required the
compilation of certain data, including the names, addresses, and phone numbers of local
emergency officials who would respond to a hazardous liquid pipeline emergency. During the
inspection, Respondent had no documentation that it had collected such data and performed the
required liaison activities. The Notice further alleged that BFPL had previously been issued a
warning for this issue.
5
The evidence in the record includes the portion of Respondent’s O&M manual requiring the
company to “Compile data (Organizations, names of contact personnel, phone no’s (emergency
and regular No’s), and addresses of all Emergency Officials within the vicinity (area of
jurisdiction) of the pipeline route or facility[sic].”6
At the hearing and in its Brief, Respondent did not contest the allegation of violation, but
provided information to demonstrate that the company has now prepared a list of all the relevant
police and fire departments, county emergency managers, and public officials in order to
maintain liaison. Respondent said that it has also become a member of the relevant state pipeline
associations, which affords the company an opportunity to maintain liaison with required
emergency responders and public officials.
After considering all of the evidence, I find that Respondent violated 49 C.F.R. § 195.402(a) and
(c)(12) by failing to follow its written procedures for establishing and maintaining liaison with
fire, police, and other appropriate public officials.
Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 195.402(a) and (c)(13), which
state:
§ 195.402 Procedural manual for operations, maintenance, and
emergencies.
(a) General. Each operator shall prepare and follow for each pipeline
system a manual of written procedures for conducting normal operations
5 In the Matter of Belle Fourche Pipeline Co., Final Order, CPF No. 5-2007-5002, at 5, 2008 WL 1981035 (Apr. 28,
2008).
6 Violation Report, Exhibit B.



4
and maintenance activities and handling abnormal operations and
emergencies . . . .
(c) Maintenance and normal operations. The manual required by
paragraph (a) of this section must include procedures for the following to
provide safety during maintenance and normal operations: . . .
(13) Periodically reviewing the work done by operator personnel to
determine the effectiveness of the procedures used in normal operation
and maintenance and taking corrective action where deficiencies are
found.
The Notice alleged that Respondent violated § 195.402(a) and (c)(13) by failing to follow the
company’s written procedures for reviewing the work done by personnel to determine the
effectiveness of O&M procedures and to take corrective action to address deficiencies.
Specifically, the Notice alleged that Section 3.8 of BFPL’s O&M manual required the company
to periodically review the work done by personnel, but at the time of the inspection, Respondent
had no records that such reviews had ever been conducted.
The evidence in the record includes Section 3.8 of BFPL’s O&M procedures, which provides
that Respondent will “review the performance of personnel and the contents of this manual at
intervals not to exceed 15 months, but at least once each calendar year, to ensure the
effectiveness of this manual.”7 The Violation Report also notes that BFPL’s compliance
coordinator stated that he did not think there had ever been a formal review of personnel work to
determine the effectiveness of the O&M procedures.8
In its Response, Respondent stated that it believed field employees had conducted the required
reviews, although the company had not yet located any specific record of such reviews. At the
hearing, Respondent presented a witness who testified that he had performed periodic review of
work done by personnel as part of the company’s operator qualification (OQ) program. During
that process, the witness explained, employees were trained to perform certain tasks, and once
qualified, would then be observed performing the task. If any issues arose during their
performance of such tasks, including deficiencies in the procedures themselves, the company
would take corrective action to change the procedures accordingly.
BFPL also introduced into evidence an affidavit by the same witness, who attested as follows:
I have periodically reviewed the work performed by Belle Fourche
Pipeline Company employees to determine the effectiveness of the
procedures found in the O&M Manual. In compliance with 49 C.F.R.
§ 195.402(c)(13), I interact with the employees and advise them on their
performance on a day to day basis, and assure that corrective action is
taken when necessary.
7 Violation Report, Exhibit C.
8 Violation Report at 6.



5
During the hearing, the Director recommended withdrawing Item 3 based on the company’s
assertions and submissions at the hearing. For this reason, Respondent provided no additional
information regarding Item 3 in its post-hearing Brief.9
After considering the evidence and the explanation provided by BFPL that the company
followed its procedures, the Director has recommended this allegation of violation be withdrawn.
Accordingly, I am withdrawing this allegation of violation.
Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 195.404(b)(1), which states:
§ 195.404 Maps and records.
(a) . . . .
(b) Each operator shall maintain for at least 3 years daily operating
records that indicate—
(1) The discharge pressure at each pump station; . . .
The Notice alleged that Respondent violated § 195.404(b)(1) by failing to maintain daily
discharge pressure records at the Guernsey Pump Station for at least 3 years. The Notice further
alleged the company did not have a pressure recording device at that pump station. Included in
the record as evidence of the violation is a photograph of the Fort Laramie pipeline and pump at
Guernsey Station, showing an absence of either a pressure recording chart or related
instrumentation for recording the discharge pressure of the pump.
10 The Violation Report also
noted that Respondent’s Guernsey Station manager told the inspector that the company did not
have any pressure records for its Fort Laramie pipeline.11
At the hearing and in its Brief, Respondent contended that the regulation does not require the
company to install or use a pressure recording device at its pump station. Rather, BFPL argued
that the regulation only requires operators to maintain daily records of discharge pressure if the
company collects such information.
12 BFPL explained that since it does not collect daily
pressure information for the Guernsey station, the company did not violate § 195.404(b)(1) by
not maintaining daily discharge pressure records. Respondent also explained that the pump at
Guernsey station is insufficient to exceed maximum operating pressure (MOP) during normal or
abnormal operations, and that the operator had previously determined that the discharge pressure
could only reach 182 pounds per square in gauge (psig), less than 20% SMYS, based on the
pump curves.
because there was no risk of overpressure.
13 The company had concluded that it did not need a pressure recording device
Section 195.404(b)(1) requires that operators maintain “daily operating records that indicate . . .
[t]he discharge pressure at each pump station.”14
The regulation does not contain any
9 Brief at 4.
10 Violation Report, Exhibit D.
11 Violation Report at 7.
12 Brief at 5.
13 A pump curve is a graphical description of a centrifugal pump’s performance, that is the pump head (or pressure)
versus the flow rate, expressed in feet of head (or feet of water) units. One foot of “head” equates to approximately
0.433 psig of “pressure.” BFPL submitted for the record the pump curve. Respondent Hearing Exhibit 15.
14 (emphasis added).



6
exemptions for pumps that will not exceed MOP, or for pumps that do not have recording
devices installed. Respondent has therefore suggested an interpretation of § 195.404(b)(1) that is
not supported by the language of the rule. Under the regulation, BFPL must have the means to
record the discharge pressure at each pump station and must maintain daily records of that
information, regardless of the particular characteristics of the pump station. The evidence
demonstrates that BFPL did not maintain daily discharge pressure records at the Guernsey Pump
Station for at least 3 years.
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 195.404(b)(1) by failing to maintain daily discharge pressure records at the Guernsey Pump
Station for at least 3 years.
Item 5: The Notice alleged that Respondent violated 49 C.F.R. § 195.404(c)(3), which states:
§ 195.404 Maps and records.
(a) . . . .
(c) Each operator shall maintain the following records for the periods
specified . . .
(3) A record of each inspection and test required by this subpart shall
be maintained for at least 2 years or until the next inspection or test is
performed, whichever is longer.
The Notice alleged that Respondent violated § 195.404(c)(3) by failing to maintain records of a
breakout tank inspection until the next inspection. Specifically, the Notice alleged that BFPL’s
tank data sheets indicated that it performed an API Standard 653 out-of-service internal
inspection of the Sussex breakout tank in 2001, and had not yet performed the next internal
inspection. The Notice further alleged that the company did not have any records from the 2001
internal inspection required to be maintained pursuant to § 195.404(c)(3). The evidence in the
record of the violation includes BFPL’s tank data sheet showing that an internal inspection of the
Sussex Breakout Tank was conducted in June 2001.
In its Response, BFPL explained that while it did perform some work on the breakout tank in
2001, it did not perform an API Standard 653 internal inspection and therefore did not maintain a
record of the work. At the hearing, Respondent presented testimony from its Area Supervisor
responsible for operations of the tank in 2001 who testified that the company did not perform an
API Standard 653 internal inspection in 2001. The witness stated that the record cited in the
Notice, which was the basis for the allegation, was actually an error, created years after 2001 as
an intended summary of historical inspections. The company further explained that the tank had
just been installed in 1997, and therefore it would not have been reasonable for the company to
perform such an in-depth internal inspection after only 4-5 years when the interval for such
inspections can be up to 20 years under the API Standard.
After considering all of the evidence in the record, I find the evidence demonstrates that it was
more likely that BFPL did not perform an API Standard 653 internal inspection in 2001 and that
the company’s record provided to PHMSA during the inspection was in error. Of particular
relevance is that the tank in question was constructed in 1997 and would not have been due for
an API Standard 653 internal inspection in 2001. Given the BFPL employee’s sworn testimony
that no such inspection occurred in 2001, and that the entry was in error, I find the evidence



7
supports withdrawing this allegation of violation. Accordingly, I am withdrawing this allegation
of violation.
Item 6: The Notice alleged that Respondent violated 49 C.F.R. § 195.406(b), which states:
§ 195.406 Maximum operating pressure.
(a) . . . .
(b) No operator may permit the pressure in a pipeline during surges or
other variations from normal operations to exceed 110 percent of the
operating pressure limit established under paragraph (a) of this section.
Each operator must provide adequate controls and protective equipment to
control the pressure within this limit.
The Notice alleged that Respondent violated § 195.406(b) by failing to have protective
equipment at the Guernsey Pump Station to control pressure from exceeding 110 percent of the
MOP during surges either at the station or on the pipeline downstream from the station. Included
in the record as evidence of the violation are photographs that show the absence of an
overpressure safety device at the Guernsey Station and on the pipeline downstream from the
pump. In addition, during the PHMSA inspection, Respondent’s station operator stated that
overpressure control devices are not needed on the Fort Laramie line because the pump curves
prove that pressure cannot exceed MOP.15
At the hearing and in its Brief, Respondent argued that the company’s pump curve demonstrates
that the Guernsey Pump Station cannot produce pressure exceeding 182 psig on the Ft. Laramie
line, which is less than 20% of the MOP of the pipeline. A witness also testified at the hearing
that the geography and flat terrain would not contribute to surges in the line. Since the pipeline
cannot exceed MOP, even during surges, BFPL argued that it is not required to provide any
additional “controls and protective equipment” to control the pressure within 110% of MOP
under the regulation. BFPL acknowledged that it could not submit for the record any
documented analysis supporting its determination that pressure could not exceed MOP other than
the pump curve.
At the hearing, the Director acknowledged that it may be conceivable for an operator to
demonstrate through a documented analysis that no additional protective pressure controls are
necessary for a pipeline based on certain characteristics of the line, such as MOP, the physical
limitations of the pump, and geography. In such a situation, however, the Director explained that
PHMSA would normally expect a rigorous surge pressure analysis and documentation to
demonstrate that no additional protective pressure controls are necessary. Both parties agreed
that pipelines can at times experience surges in pressure beyond the levels created by the pump
alone.
As explained above, a pump curve is a graphical description of a centrifugal pump’s
performance, that is, pump head (or pressure) versus flow rate. The pump curve submitted by
Respondent demonstrates the maximum head pressure that can be produced by the Guernsey
Station pump. At a zero discharge flow rate, the pump would produce a head pressure of
approximately 450 feet of water (approximately 195 psig). In addition, there is an elevation drop
15 Violation Report at 9.



8
of approximately 225 feet from Guernsey Station to the Ft. Laramie pipeline terminus.
Considering the elevation change, the pump could conceivably produce a pressure at the pipeline
terminus of approximately 675 feet of water (450 + 225), or approximately 292 psig (195 + 97),
which is far less than the 1468 psig design pressure of the pipeline.
In addition to the static condition (zero flow or “dead head”), an operator usually would also be
expected to perform an actual surge analysis to demonstrate maximum pressure that could be
reached in a transient condition, such as during a sudden valve closure or pump shutdown.
During a surge, the pressure in the line could conceivably be higher for a short period of time
than the zero flow condition described above. This is due to the pressure wave that travels inside
the pipeline during a rapid transient. In the present case, I find it that even at transient
conditions, pressure in the pipeline could not reach the design pressure of the pipeline.
Therefore, there is no need for additional controls or protective equipment under the current
operating configuration (i.e., only the current pump provides pressure to the segment).
After considering the evidence and the explanation provided by BFPL, the Director has
recommended this allegation of violation be withdrawn. Accordingly, I am withdrawing this
allegation of violation.
Item 8: The Notice alleged that Respondent violated 49 C.F.R. § 195.420(b), which states:
§ 195.420 Valve maintenance.
(a) . . . .
(b) Each operator shall, at intervals not exceeding 7½ months, but at
least twice each calendar year, inspect each mainline valve to determine
that it is functioning properly.
The Notice alleged that Respondent violated § 195.420(b) by failing to inspect mainline valves at
least twice during the 2006 calendar year and at intervals not exceeding 7½ months between
2006 and 2007. Included in the record as evidence of the violation are 17 pages of valve
inspection records from 2005 through 2008, which the Notice alleged demonstrate that BFPL
missed either or both of the maximum inspection intervals on 47 occasions during the period in
question.
At the hearing and in its Brief, Respondent acknowledged some of the violations occurred as
alleged in the Notice.
16 Specifically, BFPL acknowledged 16 instances of valves not being
inspected during the 2006 calendar year,
17 and 10 instances of valves not being inspected at 7½-
arguing that: 15 had been inspected at the proper intervals during quarterly pigging activities; 2
had been inspected at the proper intervals, but PHMSA miscalculated the 7½-month interval; 2
were valves not subject to the pipeline safety regulations; and 2 were duplicate entries on the list.
month intervals.18 Respondent contested the remaining 21 instances of missed valve inspections,
16 See Respondent Hearing Exhibit 17.
17 Those 16 instances involve the following valves: 010-001; 010-002; 010-003; 010-0056; 010-010; 010-011; 010-
101; 015-001; 015-002; 015-004; 015-005; 101-006; 101-008; 101-009; 6-inch Tie In; and Poison Draw 8-inch.
18 Those 10 instances involve the following valves: 010-005; 010-006; 010-008; 010-009; 010-010; 015-001; 015-
002; 069-0005; 6-inch Tie In; and Poison Draw 8-inch.



9
One of BFPL’s arguments, that PHMSA miscalculated the 7½-month interval, is based on the
assertion that the agency simply added 225 days to the prior valve inspection date. BFPL
contended that because the regulation establishes the maximum interval as “7½ months,” not 225
days, it was permissible for the company to perform inspections up to the 15th day of the 8th
month following the most-recent inspection. The company contended that two instances of the
alleged violations were inspections that actually occurred within this interval.
introduced evidence to support its assertions with regard to the other contested instances,
including charts and pigging logs.
19 BFPL also
After reviewing the evidence in the record, I find Respondent has demonstrated the validity of its
claims. Namely, Respondent has demonstrated that of the 21 instances of alleged violations that
Respondent contested: 17 had been inspected at the proper intervals; 2 were valves on
unregulated gathering lines not subject to this pipeline safety requirement; and 2 were duplicate
entries on the list. Accordingly, these allegations of violation are hereby withdrawn.
Furthermore, I find the regulation does not preclude Respondent’s method of calculating the 7½-
month maximum inspection interval. For this reason, Respondent has demonstrated that its
noncompliance with respect to 10 of the other instances of violations lasted, on average, for only
12 days.
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 195.420(b) by failing to inspect mainline valves at the mandated intervals on 26 occasions.
Item 9: The Notice alleged that Respondent violated 49 C.F.R. § 195.428(a), which states:
§ 195.428 Overpressure safety devices and overfill protection
systems.
(a) Except as provided in paragraph (b) of this section, each operator
shall, at intervals not exceeding 15 months, but at least once each calendar
year . . . inspect and test each pressure limiting device, relief valve,
pressure regulator, or other item of pressure control equipment to
determine that it is functioning properly, is in good mechanical condition,
and is adequate from the standpoint of capacity and reliability of operation
for the service in which it is used.
The Notice alleged that Respondent violated § 195.428(a) by failing to inspect and test pressure
limiting devices at five different locations within intervals not exceeding 15 months, but at least
once each calendar year. Specifically, the Notice alleged that: (1) BFPL failed to inspect and test
station pressure controls at the Donkey Creek and Hwy 450 stations during the 2007 calendar
year; (2) that inspection intervals of those same controls exceeded 15-month intervals by 68 days
and 98 days, respectively; (3) that BFPL exceeded the 15-month interval for inspecting and
testing pressure controls at the Seiler station by 120 days in 2007; and (4) that BFPL exceeded
the 15-month interval for inspecting and testing pressure controls at the Sussex pump station and
Guernsey terminal in 2008 by 145 days and 105 days, respectively.
The Violation Report includes nine pages of Safety Device Inspection Forms from 2006 through
2008 demonstrating that Respondent had performed inspections and tests of the pressure limiting
19 Also as a result of this calculation, Respondent maintained that certain other inspections were missed by an
average of only 12 days, not 16 days as implied in the Notice.



10
devices at intervals that exceeded the maximum 15-month interval or that were not at least once
per calendar year.
20
With regard to the alleged violation pertaining to the Donkey Creek facility, Respondent
contested the allegations on the grounds that new devices had been installed at the station in
2007. At the hearing and in its Brief, the company explained that in October 2007, it replaced
Pumps 1, 2, and 3 and added a new Pump 4 at the station, effectively restarting the inspection
intervals for those pressure controls.
The Director contended at the hearing that Respondent never demonstrated the new pumps were
actually inspected and tested (e.g., calibrated) when they were installed in 2007. In its Brief,
however, Respondent submitted additional documentation to validate that the new pumps had
been inspected and tested as part of the installation process.
After reviewing the evidence in the record, I find that Respondent has demonstrated the validity
of its claim that the Donkey Creek station was reconfigured in 2007 by replacing and adding
pumps. The pressure limiting devices installed as part of that reconfiguration were tested and
inspected as part of the installation process in October 2007, roughly 13 months after the
previous test of pressure limiting devices at Donkey Creek. For this reason, I find the evidence
supports withdrawing the alleged violation pertaining to the Donkey Creek facility.
With regard to the remaining allegations, Respondent initially argued in its Response that the
Notice failed to identify the precise equipment at issue, the equipment is not subject to
§ 195.428(a), and the regulation is impermissibly vague. At the hearing, however, Respondent
acknowledged that it understood the precise equipment at issue in the allegations and that the
devices are indeed pressure limiting devices subject to the inspection and testing requirements in
§ 195.428(a). The company also stated that it could not provide records to rebut the alleged
violation. In its Brief, BFPL acknowledged that it did not fully comply with this requirement.
21
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 195.428(a) by failing to inspect and test pressure limiting devices at the Hwy 450 and Seiler
stations in 2007, and at the Sussex pump station and Guernsey terminal in 2008. The allegations
with regard to the Donkey Creek station are withdrawn.
Item 10: The Notice alleged that Respondent violated 49 C.F.R. § 195.428(d), which states:
§ 195.428 Overpressure safety devices and overfill protection
systems.
(a) Except as provided in paragraph (b) of this section, each operator
shall, at intervals not exceeding 15 months, but at least once each calendar
year . . . inspect and test each pressure limiting device, relief valve,
pressure regulator, or other item of pressure control equipment to
determine that it is functioning properly, is in good mechanical condition,
and is adequate from the standpoint of capacity and reliability of operation
for the service in which it is used . . . .
20 Violation Report, Exhibit H.
21 Brief at 16.



11
(d) After October 2, 2000, the requirements of paragraphs (a) and (b)
of this section for inspection and testing of pressure control equipment
apply to the inspection and testing of overfill protection systems.
The Notice alleged that Respondent violated 49 C.F.R. § 195.428(d) by failing to inspect and test
certain overfill protection systems (i.e., high level alarms) at intervals not exceeding 15 months,
but at least once each calendar year. Specifically, the Notice alleged that BFPL had never
inspected and tested the high level alarms at three breakout tanks associated with the Sussex
Diesel Line: the Sussex Pump Station Breakout Tank; Davis Station Breakout Tank (Tank 74);
and Hawk Point Terminal Breakout Tank.
Evidence in the record includes the PHMSA inspector’s notes from the inspection, during which
BFPL could not provide any records to demonstrate the high-level alarms had been inspected and
tested since 2001. In addition, the PHMSA inspector interviewed BFPL personnel who stated
that they did not think the high-level alarms had been inspected and tested at any frequency.
22
Respondent initially argued in its Response that the Notice failed to identify the precise
equipment at issue, the equipment is not subject to § 195.428(d), and the regulation is
impermissibly vague. At the hearing, however, Respondent acknowledged that overfill
protection (high level) alarm devices existed on the three tanks identified in the Notice, and that
the company did not have records to demonstrate the devices had been tested at the required
intervals under the regulation. The company explained, however, that it could provide records of
“hand gauging” the tanks every month to verify the accuracy of the levels displayed by the
SCADA system.
The Director explained at the hearing that hand gauging would not have tested the mechanical-
electrical high alarm switches on the tanks, but would only test the accuracy of the SCADA tank
level indications. In its Brief, however, Respondent contended that hand gauging resulted in
“substantial compliance” with § 195.428(d), explaining again that the company verified that tank
levels were consistent with SCADA read-outs. The company contended that it had also “visited”
each breakout tank at least once daily.
The overfill protection (high level) alarm devices on the three tanks identified in the Notice send
an alarm to personnel when product in the tank is approaching a level that is close to overfilling
or when the tank has been overfilled. Respondent’s hand gauging to verify the accuracy of
SCADA tank level indicators never actually inspected and tested the overfill alarm devices to
determine they were functioning properly and were adequate for the service in which they were
to be used. Therefore the hand gauging practice did not achieve compliance with § 195.428(d).
There is also no evidence that daily “visits” to the tanks achieved compliance.
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 195.428(d) by failing to inspect and test the overfill protection systems at three breakout tanks.
Item 11: The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b), which states:
§ 195.432 Inspection of in-service breakout tanks.
22 Violation Report at 16.



12
(a) . . . .
(b) Each operator shall inspect the physical integrity of in-service
atmospheric and low-pressure steel aboveground breakout tanks according
to section 4 of API Standard 653 . . . .
23
The Notice alleged that Respondent failed to inspect the physical integrity of certain in-service
breakout tanks according to Section 4 of API Standard 653. Section 4 provides for the
evaluation of the suitability of existing tanks for continued service and for making decisions
involving repairs. Section 4 references the tank inspection intervals contained in Section 6 of the
API Standard.
Specifically, the Notice alleged that Respondent failed to perform an external inspection of the
Sussex Breakout Tank within the 5-year interval prescribed in API Standard 653, Section 6.3.2.
Evidence in the record of the violation includes tank data sheets that fail to document any
external inspections of the tank between 2001 and 2006.24
This Item is related to Item 5, which alleged that Respondent failed to maintain a record of the
internal inspection of the Sussex breakout tank in 2001. In Item 5, I found that Respondent
never performed an internal inspection of the tank in 2001 based on a preponderance of the
evidence. In its Brief, BFPL characterized the separate alleged violation of § 195.432(b) in Item
11 as “premised on the mistaken assumption by PHMSA that an API 653 Internal Inspection
occurred in 2001. Since no such inspection occurred, there was no obligation to conduct the
cited external inspection.”25
Respondent’s contention, however, is not an accurate characterization of either the alleged
violation in Item 11 or the requirement in § 195.432(b). This allegation is that Respondent failed
to perform an external inspection of the Sussex Breakout Tank at the interval set forth in API
Standard 653, Section 6.3.2, which provides: “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.
” The requirement to perform an external (in-service)
inspection of “all tanks” every 5 years is independent of the separate requirement in API
Standard 653 to perform internal (out of service) tank inspections. Regardless of whether or not
Respondent completed an internal inspection in 2001, the regulation still mandated that it
conduct an external inspection at the maximum interval of 5 years. Since the evidence in the
record demonstrates that Respondent never conducted an external inspection in the 5-year period
between 2001 and 2006, BFPL failed to comply with this requirement.
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 195.432(b) by failing to inspect the physical integrity of the breakout tank according to API
Standard 653.
23 Section 195.432(b) was amended after the inspection. It presently reads: “Each operator must inspect the
physical integrity of in-service atmospheric and low-pressure steel aboveground breakout tanks according to API
Standard 653 . . . .” Pipeline Safety: Periodic Updates of Regulatory References to Technical Standards and
Miscellaneous Edits, 75 Fed. Reg. 48,593, 48,607 (Aug. 11, 2010).
24 Violation Report, Exhibit E.
25 Brief at 19.



13
Item 12: The Notice alleged that Respondent violated 49 C.F.R. § 195.436, which states:
§ 195.436 Security of facilities.
Each operator shall provide protection for each pumping station and
breakout tank area and other exposed facility (such as scraper traps) from
vandalism and unauthorized entry.
The Notice alleged that Respondent violated § 195.436 by failing to provide adequate protection
from vandalism and unauthorized entry for each pump station and breakout tank. Specifically,
the Notice alleged that BFPL had not installed any perimeter fencing around the Donkey Creek
Pump Station. The Notice further alleged that BFPL had only installed 4.5-foot high woven steel
grid wire fence with 2 strands of barbed wire around the Sussex Pump Station and Sussex
Breakout Tank, which were not adequate to prevent vandalism and unauthorized entry to the
facility.
The evidence in the record includes photographs that show the absence of fencing around
Donkey Creek Pump Station and a representative portion of the type of fencing at the Sussex
Pump Station and Breakout Tank.
26 The Violation Report further noted that Respondent’s
compliance coordinator stated during the inspection that security fencing was not necessary for
either facility because of the remote location and presence of personnel at the Donkey Creek
facility.27
At the hearing and in its Brief, Respondent contested the allegation of violation, stating there is
adequate protection at Donkey Creek through 24/7 staffing and because the location of the
station is two miles away from the closest public road. As to the Sussex facility, BFPL argued
that the facility has a security fence as documented in the Notice and is located five miles from
the closest public road.
Respondent also asserted that § 195.436 does not specify a uniform standard, and that protection
for each station may differ depending on the unique circumstances of the facility. BFPL cited to
a previous agency interpretation that the company argued states that fencing is not required.28
Respondent also claimed that during a previous PHMSA inspection, agency inspectors had
accepted that the remoteness of the facilities contributed to the adequacy of the security.
At the hearing, the Director argued that the previous agency interpretation established that
adequate security fencing or continuous surveillance is required under § 195.436 to protect
against vandalism and unauthorized entry. The Director also explained that at Donkey Creek,
the on-site person has job duties other than surveillance, including operation of the pipeline.
Although not cited by either party during the hearing, PHMSA has previously issued final orders
deciding this issue of contention.29
As those cases demonstrate, PHMSA has routinely rejected
26 Violation Report, Exhibit I.
27 Violation Report at 20.
28 Brief at 20 (citing OPS Hearing Exhibit 7: Interpretation of 49 C.F.R. § 195.436 (Aug. 13, 1980)).
29 See, e.g., In the Matter of Sunoco Pipeline, L.P., Final Order, CPF No. 4-2007-5040, 2010 WL 5761108 (Dec. 16,
2010); In the Matter of Plains Pipeline, L.P., Final Order, CPF No. 4-2009-5005, 2010 WL 2228553 (Apr. 6, 2010);



14
the argument that § 195.436 permits a lower level of protection merely because a facility is
located in a remote area. PHMSA has also rejected the argument that livestock fencing provides
adequate protection from vandalism and unauthorized entry. The 1980 interpretation cited by
both parties states that while “fencing is not necessarily required, one of the ways to comply with
this regulation would be to construct a fence adequate to protect the facility from vandalism and
wire livestock fence or an eight-foot chain link fence with no barbed wire are both inadequate to
unauthorized entry.”30 The interpretation explains further that either a simple four-strand, barbed
meet the requirements of the regulation. In addition, surveillance that consisted of only hourly
inspections also did not meet the requirements.
The evidence in the record demonstrates that Respondent’s Donkey Creek facility has no
perimeter fencing and no other means of protecting the facility from vandalism and unauthorized
entry. While there is staffing at the facility, the mere presence of an individual is not sufficient
to provide continuous security when that person has primary duties other than security
surveillance, including such duties as operating the pipeline facility.
With regard to the Sussex Pump Station and Breakout Tank, the evidence in the record
demonstrates that it is surrounded by a fence 4.5 feet high, comprised of wire grid, concrete
reinforced panels with two strands of barbed wired above the panels. Based on the examples of
inadequate security fencing from the 1980 interpretation and prior cases, I similarly find this
fence to be inadequate because it is only 4.5 feet high and has large grid openings that would be
easy hand or foot holds with which to climb. The remoteness of either facility does not, by itself,
constitute additional security precautions. In fact, remoteness could make such a facility more
attractive to vandalism or unauthorized entry.
For the above reasons, I find that Respondent violated 49 C.F.R. § 195.436 by failing to provide
adequate protection from vandalism and unauthorized entry for the Donkey Creek Pump Station
and the Sussex Pump Station and Breakout Tank.
Item 13: The Notice alleged that Respondent violated 49 C.F.R. § 195.577(a), which states:
§ 195.577 What must I do to alleviate interference currents?
(a) For pipelines exposed to stray currents, you must have a program
to identify, test for, and minimize the detrimental effects of such currents.
The Notice alleged that Respondent violated § 195.577(a) by failing to have and implement a
program to identify, test for, and minimize the detrimental effects of stray currents. Specifically,
the Notice alleged that BPFL’s cathodic protection monitoring records for the 12-inch Donkey
Creek Pipeline in the area of Guernsey and Ft. Laramie stations for the 2006 calendar year show
several test stations with high “off” levels, commonly indicative of cathodic protection
interference currents adversely affecting a pipeline. The Notice alleged that BFPL had not taken
steps to perform an interference study to determine if there were interference currents or to
mitigate any interference currents that existed.
and In the Matter of Jayhawk Pipeline, L.L.C., Final Order, CPF No. 3-2002-5021, 2003 WL 25429861 (Dec. 11,
2003).
30 OPS Hearing Exhibit 7.



15
The evidence in the record includes the cathodic protection survey records for the pipeline from
January 2006 to December 2008.
31 In addition, during the inspection, BFPL’s Wyoming
Corrosion Supervisor stated that performing interference current investigations was problematic
because BFPL could not get cooperation from other pipeline operators in the area.32
In response to the allegation, Respondent contended both that the pipeline was not exposed to
stray currents, and that even if the pipeline had been exposed to stray currents, BFPL had a
program in place to identify, test for, and minimize the detrimental effects of such currents. At
the hearing, Respondent contended that the readings referenced in the Notice did not indicate
there were any detrimental stray currents because BFPL knew the source of the currents was
other parties’ pipelines, and that the source was not deleterious to Respondent’s pipeline. In its
Brief, BFPL explained that the pipelines in the area “are tied together with either piping,
electrical grounding between the different pipeline companies in the area, or by bonds.” In
addition, BFPL explained that the readings relied upon by PHMSA were not accurate because
not all rectifiers had been interrupted, which gave “higher structure IR readings than if all the
rectifiers tied to this line were interrupted.” Respondent also submitted evidence that in July
2009, the company performed a close interval survey (CIS) for the pipeline, which confirmed
that no “detrimental stray currents” were impacting BFPL pipeline facilities in that area.
The evidence in the record of the cathodic protection survey readings for Respondent’s pipeline
indicate there were certain areas with high “off” levels. Even if not all rectifiers had been
interrupted, as Respondent contended, the indication by the readings was that there were
interference currents in the area of Respondent’s pipeline. At a minimum, Respondent was
required to have a program to identify and test those indications of interference currents.
Respondent’s defense to the allegation is based on its contention that it understood the source of
these interference currents and believed they were not detrimental. Whether or not Respondent
knew the source of interference currents in the area of its pipeline, or believed the source of those
currents was not detrimental, § 195.577 still requires BFPL to have a program to identify and
address those stray currents. The company’s belief that interference currents were not
detrimental does not excuse it from the requirement to have a program for identifying and testing
to ensure they are indeed not detrimental.
The third-party who performed a CIS for Respondent in 2009 stated in a follow-up letter that,
“Immediately prior to performing the CIS, potentials were measured at several representative test
stations in the test area. Foreign CP Systems in the vicinity were then cycled to determine if they
affected the subject pipeline. Current interrupters were then installed at Foreign CP Systems
statement confirms there were stray currents in the area of Respondent’s pipeline, that is,
currents from foreign sources were affecting the cathodic protection system on the pipeline.
which were found to affect the pipeline segment along with all Company CP Systems.”33 This
Since all indications were that Respondent’s pipeline was being exposed to stray currents, BFPL
was required to have a program to identify, test for, and minimize the detrimental effects of such
currents.
31 Violation Report, Exhibit J.
32 Violation Report at 21.
33 Respondent Hearing Exhibit 8.



16
Respondent further contended that it had a program in place to identify, test for, and minimize
the detrimental effects of such currents. BFPL claimed the reports used by PHMSA in support
of the allegation demonstrated this program was in place and implemented.
After reviewing this evidence, however, I fail to find how these cathodic protection survey
readings could constitute “a program to identify, test for, and minimize the detrimental effects of
such currents.
” The records are merely cathodic protection survey readings and contain no
indication of stray current identifications, documentation of any testing of such currents for
detrimental effects, or discussion of any efforts to minimize detrimental effects. Nor do I find
any other evidence in the record that Respondent ever identified, tested for, or took actions to
minimize the detrimental effects of any stray currents at that location until after PHMSA’s
inspection of the facility in August 2008.
Contrary to Respondent’s contention, the fact that BFPL took measures to investigate the stray
currents after PHMSA’s inspection does not demonstrate that BFPL was in compliance at the
time of PHMSA’s inspection. Prior to the PHMSA inspection, BFPL had merely assumed there
were no problems in the area of its pipeline despite indications of stray currents, and never
prepared and followed written procedures for determining the accuracy of its assumption. It was
not until PHMSA identified the issue during an inspection that BFPL contracted for a third-party
to study the issue.
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 195.577(a) by failing to have and implement a program to identify, test for, and minimize the
detrimental effects of stray currents.
Item 14: The Notice alleged that Respondent violated 49 C.F.R. § 195.579(a), which states:
§ 195.579 What must I do to mitigate internal corrosion?
(a) General. If you transport any hazardous liquid or carbon dioxide
that would corrode the pipeline, you must investigate the corrosive effect
of the hazardous liquid or carbon dioxide on the pipeline and take
adequate steps to mitigate internal corrosion.
The Notice alleged that Respondent violated § 195.579(a) by failing to investigate the corrosive
effect of the hazardous liquid transported by its pipeline and to take steps to mitigate internal
corrosion. Specifically, the Notice alleged that BFPL had experienced at least three pipeline
leaks since 2006 due to internal corrosion, but never conducted an investigation of the corrosive
effect of the hazardous liquid or took steps to mitigate the condition.
The evidence in the record includes documentation of the following four leaks on BFPL’s
pipeline system that were attributed to internal corrosion: (1) on April 30, 2006, near McKenzie,
North Dakota, 25 barrels of crude oil were released during a failure; (2) on December 22, 2007,
near Gillette, Wyoming, 40 barrels were released during a failure; (3) on July 15, 2008, near
Gillette, Wyoming, 550 barrels were released during a failure; and (4) on March 18, 2009, near
Moorcroft, Wyoming, 32 barrels were released during a failure of a non-regulated gathering line.
The first three failures were required to be reported under 49 C.F.R. § 195.50.
The record also includes accident report forms filed by Respondent for each of the three
reportable accidents. All three forms show that Respondent determined the cause of each failure



17
to be internal corrosion.34 The Violation Report noted that during the PHMSA inspection,
BFPL’s DOT Compliance Coordinator stated that the company had not conducted an internal
corrosion investigation in accordance with § 195.579(a).35
At the hearing and in its Brief, Respondent argued there is a discrepancy between the allegation
in the Notice and the actual regulatory requirement. While the Notice alleged that Respondent
was required to investigate corrosive effects if the product in its pipeline “could corrode a
pipe,”36 BFPL contended that the regulation states that investigation of corrosive effects is only
required when an operator transports a hazardous liquid that “would corrode the pipeline.
”37
BFPL argued the later requires a higher “threshold level of information or evidence to trigger the
requirement” represented by prior knowledge or a reasonable belief on the part of the operator
that the product would indeed corrode the pipeline.38
BFPL contended further that it never had knowledge or a reasonable belief that the product
transported would corrode the pipeline. The various leaks identified in the Notice, Respondent
asserted, did not cause the company to know or reasonably believe there was a risk of internal
corrosion because the leaks were unrelated to one another, happened in two different states,
involved different crude, occurred at different times, and two of them occurred on inactive line
segments where there could have been standing oil or water in the pipe. Since Respondent did
not know or reasonably suspect that the product transported would corrode the pipeline, BFPL
maintained that it did not have a regulatory duty to investigate the product for corrosive effects.39
PHMSA has publicly communicated to pipeline operators that § 195.579(a) requires operators to
determine if the hazardous liquids transported could corrode the pipeline, and the agency has
never implied, as Respondent suggests, that there must first be confirmed knowledge or
reasonable belief on the part of the operator that the product will cause internal corrosion. For
example, PHMSA published an Advisory Bulletin in the Federal Register reminding operators
that the regulations “require operators to determine if the hazardous liquids they are transporting
could corrode the pipeline.”40 In addition, the original agency rulemaking that promulgated §
195.579(a) explained in the preamble that the standard “requires operators to investigate the
effects of transporting hazardous liquid or carbon dioxide which could corrode the pipeline, and
take adequate steps to mitigate corrosion.”41
34 Violation Report, Exhibit K.
35 Violation Report at 22.
36 Notice at 8 (emphasis added).
37 § 195.579(a) (emphasis added).
38 Brief at 24.
39 In its initial Response, Belle Fourche claimed the regulation is also “impermissibly and unconstitutionally vague
and ambiguous” because PHMSA has not defined in the regulation the circumstances when an operator must
investigate the corrosive effect of a hazardous liquid. BFPL did not raise this constitutional argument at the hearing
or in its Brief. For the reasons set forth in this decision, I find the regulation is not “impermissibly and
unconstitutionally vague and ambiguous,” and that the agency has also provided additional guidance to operators
regarding the applicability of this safety standard.
40 Advisory Bulletin on the Proper Identification of Internal Corrosion Risk, 73 Fed. Reg. 71,089 (Nov. 24, 2008).
41 Final Rule on Controlling Corrosion on Hazardous Liquid and Carbon Dioxide Pipelines, 66 Fed. Reg. 66,994,
67,000 (Dec. 27, 2001).



18
PHMSA has applied the regulation in the same manner. In a prior enforcement decision that is
similar in many respects to the present case, PHMSA determined that a pipeline operator
violated § 195.579(a) when it failed to investigate the corrosive effect of the product transported
after experiencing several leaks caused by internal corrosion.
and on a lateral pipeline used for inputting trucked barrels of crude oil. Even though the operator
had investigated the corrosive effects of the product on its mainline pipe, the operator violated
§ 195.579(a) when it failed to perform the same investigation for such non-mainline pipes where
the leaks had occurred.
42 The leaks occurred on a dead leg
BFPL’s situation is similar in that the company has experienced multiple leaks on its pipeline
system due to internal corrosion, some of which occurred on idle or non-mainline pipe. In this
case, however, there is no evidence that Respondent ever investigated the corrosive effects of the
product, even on its mainline pipeline. The company may not ignore information about internal
corrosion leaks on its pipeline merely because it does not consider the leaks to be related in time
or location. Likewise, the fact that leaks occurred on idle lines or dead legs is no excuse not to
investigate the corrosive effects.
Internal corrosion may be caused by the corrosive effects of product being transported through a
pipeline system. Even if an operator believes that the commodity it transports is not normally
corrosive, PHMSA has found that contaminants can be introduced to noncorrosive products
during production and manufacturing processes, such as during upset conditions at a processing
plant or refinery. During upset conditions, untreated product may bypass the treatment process
and enter the pipeline, introducing corrosive materials.
Given the pipeline failures caused by internal corrosion, BFPL was required under § 195.579(a)
to investigate the corrosive effects of the hazardous liquid transported in its pipeline system. The
evidence demonstrates that BFPL failed to perform such an investigation.
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 195.579(a) by failing to investigate the corrosive effects of the hazardous liquid transported by
its pipeline.
These findings of violation will be considered prior offenses in any subsequent enforcement
action taken against Respondent.
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
42 In the Matter of Sunoco Pipeline, L.P., Final Order, CPF No. 4-2007-5040, 2010 WL 5761108 (Dec. 16, 2010).



19
of Respondent’s prior offenses; the 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 $221,200 for the violations in Items 1, 5, 8, 9, 10,
and 11. Since Items 1 and 5 have been withdrawn, penalties are not assessed for these items.
Item 8: The Notice proposed a civil penalty of $30,800 for Respondent’s violation of 49 C.F.R.
§ 195.420(b). As discussed above, I found that BFPL failed to inspect mainline valves on 26
occasions at the maximum intervals required by regulation. I also withdrew allegations that
Respondent violated the regulation on 21 additional occasions.
In its Brief, Respondent argued that the penalty should be reduced for several reasons. First,
Respondent contended, and I agree, that the circumstances of the violation warrant a reduction to
the civil penalty to reflect that I have withdrawn 21 of the 47 instances of the alleged violation.
Second, Respondent argued there was a “lack of any risk to health or safety” by the violation. I
disagree with this contention. Properly functioning mainline valves are essential to the safe
operation of hazardous liquid pipeline systems; they are used to limit the volume of product
released in the event of a spill. One purpose of the mandatory valve inspection interval set forth
in § 195.420(b) is to ensure that valve problems are identified and corrected before they impact
the safety of the pipeline system. BFPL failed to inspect approximately 21 mainline valves at
proper intervals on 26 occasions. Accordingly, I find BFPL’s failure to perform these timely
inspections presented a pipeline safety risk.
Third, Respondent argued that the Violation Report erroneously stated there were potential
impacts to high consequence areas (HCAs) as a result of the violation, when there are not any
HCAs in the area of the valves that had missed inspections. The only evidence presented in the
Violation Report of the location of HCAs are several maps, but they are of such a large scale,
and are not supported by additional documentation, that it is inconclusive as to whether there are
the record, I agree the evidence does not support finding potential impacts to HCAs. In this
regard, the gravity of the violation warrants a reduction to the proposed civil penalty.
any HCAs in the area of the valves that had missed inspections.43 Accordingly, after reviewing
Fourth, BFPL argued that the Violation Report included no evidence of the degree of culpability,
but rather stated simply that the company was “culpable” because it had knowledge of the
regulation. In prior final orders, I have found that when evaluating an operator’s culpability, I
determine the extent to which the company deserves the blame for the violation that occurred.44
In this case, as the operator of the pipeline facility, BFPL is responsible for compliance and
therefore is culpable for these violations of the pipeline safety regulations. I find no reason to
determine there is any lesser degree of culpability on the part of Respondent for these violations.
43 Violation Report, Exhibit L.
44 In the Matter of Alyeska Pipeline Service Co., Decision on Petition for Reconsideration, CPF No. 5-2006-5018,
2010 WL 2228550, at 2-3 (Mar. 1, 2010) (citing the American Heritage Dictionary of the English Language 442
(4th ed. 2000)).



20
Fifth, Respondent argued that it had demonstrated good faith in attempting to achieve
compliance, as the company had implemented a “vigorous valve inspection program, that [the
missed inspections] were isolated occurrences, and most importantly that a majority of the valves
inspections in a timely manner, the numerous instances of missed valve inspections in this case
preclude any penalty reduction for good faith in attempting to achieve compliance.
at issue in fact were inspected.”45 While Respondent may have performed other valve
Sixth, Respondent contested the statement in the Violation Report that “BFPL has a poor record
of compliance with Part 195 requirements,” since there was no finding that BFPL previously
violated this regulation. In prior final orders, I have found that “[w]hile a repeat violation of the
exact same regulatory section is certainly the most acute example of a prior offense, I am not
precluded from considering [a respondent’s] overall compliance history, including all previous
violations of the pipeline safety regulations regardless of regulatory section number.
”46
Accordingly, when evaluating BFPL’s history of prior offenses, “I may consider not only
instances of past violations of the same regulation, but also the company’s history of other
offenses, such as prior violations of other regulations, the extent to which such violations
resulted in civil penalties, and whether corrective action was necessary.”47
With regard to history of prior offenses, the Violation Report cited three prior enforcement
actions issued against BFPL in the five-year period preceding the Notice in this case. In the prior
enforcement actions, Respondent was found to have committed approximately 11 violations of
the pipeline safety regulations, requiring the agency to order specific corrective measures to
ensure compliance. In addition, those violations resulted in more than $90,000 in civil penalties.
Accordingly, I have weighed Respondent’s history of prior offenses and find that when viewed
as a whole, it supports the proposed penalty and does not warrant any reduction.
Finally, BFPL argued the penalty should be reduced to reflect relatively lower penalty
assessments in other PHMSA enforcement actions. Specifically, Respondent cited a previous
final order in which PHMSA assessed a lower penalty against a different operator for failing to
inspect and test nine mainline valves in violation of § 195.420(b).
48
PHMSA sets civil penalties by applying the statutory assessment criteria on a case-by-case basis.
Given the unique facts of each offense, operating conditions of each pipeline, an operator’s
individual compliance history, how the violation was discovered, its duration, whether the
operator made a good faith effort to comply with the regulation prior to the inspection, and
whether there was any immediate or potential safety or environmental impacts, it is not
uncommon for there to be some variance in the penalties assessed for different operators’
violation of the same code section. This fact-sensitive approach is consistent with PHMSA’s
largely performance-based regulatory scheme, which involves the consideration of risk factors
45 Brief at 12.
46 Alyeska Pipeline Service Co., CPF No. 5-2006-5018, at 3. See also 49 U.S.C. § 60122(b)(2)(B) and 49 C.F.R. §
190.225(b)(2), which authorizes PHMSA to consider such other matters as justice may require in determining the
amount of a civil penalty.
47 Alyeska Pipeline Service Co., CPF No. 5-2006-5018, at 3.
48 See In the Matter of Texas Eastern Petroleum Products Co., Final Order, CPF No. 3-2004-5027, 2006 WL
3825327 (Jan. 3, 2006).



21
and complexities unique to each pipeline system. Moreover, PHMSA has found it appropriate to
increase many of its civil penalties over the years, including those for violations of
assessment criteria.
§ 195.420(b).49 Therefore I do not find this is a reason to reduce the penalty in light of the other
Accordingly, having reviewed the record and considered the assessment criteria, I assess
Respondent a reduced civil penalty of $15,800 for its violation of § 195.420(b).
Item 9: The Notice proposed a civil penalty of $62,100 for Respondent’s violation of 49 C.F.R.
§ 195.428(a). As discussed above, I found that BFPL failed to inspect and test station pressure
limiting devices at the Hwy 450 Station, Seiler Station, Sussex Pump Station, and Guernsey
Terminal. I have withdrawn the allegations with regard to the Donkey Creek station.
In its Response and Brief, Respondent argued that the penalty should be reduced for several
reasons. First Respondent contended, and I agree, that the circumstances of the violation warrant
a reduction to the civil penalty to reflect that I have withdrawn the allegations of violation with
regard to the Donkey Creek station.
Second, Respondent argued “there was no risk of harm to the environment or to public safety”
from the violation. I disagree with this assertion, however. Properly functioning pressure
control equipment provides critical protection against pipeline system failures caused by
overpressure. Regular inspections of overpressure protection devices allow operators to identify
and repair problems before more serious incidents occur, such as pipeline system failures. In
fact, pipeline failures are known to have occurred as a direct result of a pipeline operator failing
to perform regular inspections under this regulation.
perform such inspections presented a pipeline safety risk.
50 Accordingly, I find BFPL’s failure to
Third, Respondent contested the statements in the Violation Report that suggested the violations
“could potentially impact” populated and ecological HCAs, including the North Platte River.
Specifically, BFPL argued with regard to Highway 450 and Sussex stations that there are no
HCAs that could be affected. At Guernsey terminal, Respondent contended that it would not be
possible to experience an overpressure situation. Respondent also introduced as Exhibit 22 spill
modeling data related to the North Platte River, which the company argued proves that a spill
could not impact the river. Respondent did not discuss Seiler Station specifically. After
reviewing the record, I find there is an absence of conclusive evidence of potential impacts to
HCAs by this noncompliance. In this regard, the gravity of the violation warrants a reduction to
the proposed civil penalty.
Fourth, BFPL argued that the Violation Report included no evidence of any degree of
culpability, but rather stated the company was “culpable” simply because it had knowledge of
the regulation. For the same reasons expressed in Item 8, as operator of the pipeline, BFPL is
responsible for compliance and therefore is culpable for these violations of the pipeline safety
49 See, e.g., In the Matter of Nustar Logistics, L.P., F/K/A Valero Logistics Operations, L.P., CPF No. 4-2005-5048,
2009 WL 1211363 (Mar. 11, 2009) (assessing a civil penalty of $105,000 for violation of § 195.420(b)).
50 See, e.g., In the Matter of Jayhawk Pipeline, LLC, Final Order, CPF No. 3-2008-5006, 2010 WL 5761106 (Dec.
16, 2010).



22
regulations. I find no reason to determine there is any lesser degree of culpability on the part of
Respondent for these violations.
Fifth, Respondent contested the statement in the Violation Report that “BFPL has a poor record
of compliance with Part 195 requirements,” since there was no finding that BFPL previously
violated this regulation. For the same reasons expressed in Item 8, I find that when viewed as a
whole, Respondent’s history of prior offenses support the proposed penalty and do not warrant
any reduction. Furthermore, the Violation Reported confirmed that Respondent has previously
been found in violation of this specific regulation.51
Sixth, Respondent argued the proposed penalty “does not reflect the good faith efforts of BFPL
to comply, including corrective measures already implemented.
record, however, that BFPL took corrective measures to achieve compliance. Regardless,
corrective measures taken after the violation has already been identified by PHMSA do not
warrant a penalty reduction.
”52 I do not find evidence in the
Finally, BFPL argued the penalty should be reduced to reflect lower penalty assessments in prior
cases. For the reasons stated above, it is appropriate for the civil penalties in this case to differ
from prior cases given the unique facts of each case and that PHMSA has increased civil
penalties over the years, including those for violations of § 195.428(a).53
Accordingly, having reviewed the record and considered the assessment criteria, I assess
Respondent a reduced civil penalty of $42,000 for its violation of § 195.428(a).
Item 10: The Notice proposed a civil penalty of $30,800 for Respondent’s violation of 49 C.F.R.
§ 195.428(d). As discussed above, I found that BFPL failed to inspect and test the overfill
protection systems at three breakout tanks.
In its Response, BFPL contested the penalty assessment “because it is inconsistent with
enforcement in similar cases, is disproportionate to the nature and gravity of the alleged
violation, and does not reflect the good faith efforts of BFPL to comply, including corrective
measures already implemented, among other reasons.”54 At the hearing and in its Brief, BFPL
did not further clarify these general arguments, but requested that PHMSA consider its practice
of hand gauging as good faith efforts “to comply with the ultimate objectives of section
195.428(d).
”55
Respondent’s violation of § 195.428(d) was not merely an inspection missed by several days, but
rather an extended period of noncompliance. BFPL never inspected and tested the high level
alarms at the three breakout tanks. Overfill protection systems provide crucial protection against
spills and regular inspections and tests of such systems are key to ensuring that these systems
51 Violation Report at 23. See In the Matter of Belle Fourche Pipeline Co., Final Order, CPF No. 5-2004-5010, at 5
(Dec. 11, 2006).
52 Response at 11.
53 For example, in Jayhawk Pipeline, CPF No. 3-2008-5006, cited above, PHMSA assessed a civil penalty of
$96,000 for violation of § 195.428(a).
54 Response at 12-13.
55 Brief at 18.



23
operate properly. Accordingly, I find BFPL’s failure to perform such inspections presented a
pipeline safety risk, and that the civil penalty proposed is appropriate given the nature,
circumstances and gravity of the violation. As the operator of the pipeline facility, BFPL is also
culpable for this violation of the pipeline safety regulations.
With regard to BFPL’s statement in its Response that the penalty is inconsistent with other
enforcement cases, Respondent did not cite to any other enforcement cases. For the reasons
stated above, I find it is appropriate for civil penalties to differ from one case to another given
the unique facts of each case.
Finally, BFPL requested that PHMSA consider its practice of hand gauging as good faith efforts
to comply with the “ultimate objectives” of the regulation. As noted above, hand gauging was
performed to verify that tank level indicators on its SCADA system were accurate. The gauging
did not actually test the overfill alarm devices to determine they were functioning properly.
Moreover, there is no evidence in the record that Respondent undertook such hand gauging for
the purpose of attempting to comply with § 195.428(d). Lastly, with regard to any “corrective
measures already implemented,” I do not find evidence in the record that BFPL took corrective
measures to achieve compliance. Therefore I do not find such practice warrants a penalty
reduction for good faith.
I have also weighed Respondent’s history of prior offenses and find that when viewed as a
whole, it supports the proposed penalty and does not warrant any reduction.
Accordingly, having reviewed the record and considered the assessment criteria, I assess
Respondent a civil penalty of $30,800 for its violation of § 195.428(d).
Item 11: The Notice proposed a civil penalty of $43,300 for Respondent’s violation of 49 C.F.R.
§ 195.432(b). As discussed above, I found that BFPL failed to perform an external inspection of
the Sussex Breakout Tank at the required interval established by API Standard 653.
In its Response, BFPL contested the penalty assessment “because it is inconsistent with
enforcement in similar cases, is disproportionate to the nature and gravity of the alleged
violation, and does not reflect the good faith efforts of BFPL to comply, including corrective
however, BFPL did not further clarify these general arguments.
measures already implemented, among other reasons.”56 At the hearing and in its Brief,
With regard to nature, circumstances, and gravity, I find Respondent’s failure to inspect the
physical integrity of its breakout tank at the proper interval to evaluate the suitability for
continued service presented a risk to pipeline safety that supports the proposed civil penalty. As
the operator of the pipeline facility, BFPL is culpable for this violation of the pipeline safety
regulations.
For the reasons stated above, it is appropriate for civil penalties to differ from one case to another
given the unique facts of each case. I have also weighed Respondent’s history of prior offenses
and find that when viewed as a whole, it supports the proposed penalty and does not warrant any
56 Response at 13.



24
reduction. Furthermore, the Violation Reported confirmed that Respondent has previously been
found in violation of this regulation.57
Lastly, with regard to any “corrective measures already implemented,” although Respondent has
taken corrective measures to achieve compliance, such measures taken after the violation has
already been identified by PHMSA do not warrant a penalty reduction.
Accordingly, having reviewed the record and considered the assessment criteria, I assess
Respondent a civil penalty of $43,300 for its violation of § 195.432(b).
In summary, having reviewed the record and considered the assessment criteria for each of the
Items cited above, I assess Respondent a total civil penalty of $131,900.
Respondent has not provided any evidence suggesting that Respondent is unable to pay the
proposed civil penalty. Therefore, I find Respondent is able to pay the penalty without adversely
affecting its ability to continue in business.
Payment of the civil penalty must be made within 20 days of receipt of this Final Order. Federal
regulations (49 C.F.R. § 89.21(b)(3)) require this payment be made by wire transfer, through the
Federal Reserve Communications System (Fedwire), to the account of the U.S. Treasury.
Detailed instructions are contained in the enclosure. Questions concerning wire transfers should
be directed to: Financial Operations Division (AMZ-341), Federal Aviation Administration,
Mike Monroney Aeronautical Center, P.O. Box 269039, Oklahoma City, OK 73125; (405) 954-
8893.
Failure to pay the $131,900 civil penalty will result in accrual of interest at the current annual
rate in accordance with 31 U.S.C. § 3717, 31 C.F.R. § 901.9, and 49 C.F.R. § 89.23. Pursuant to
those same authorities, a late penalty charge of six percent (6%) per annum will be charged if
payment is not made within 110 days of service. Furthermore, failure to pay the civil penalty
may result in referral of the matter to the Attorney General for appropriate action in a United
States District Court.
COMPLIANCE ORDER
The Notice proposed a compliance order with respect to Items 2, 3, 4, 6, 10, 11, 12, 13, and 14 in
the Notice for the violations described above.
Since Items 3 and 6 have been withdrawn, the associated terms of the proposed compliance order
are not included for those items.
With regard to the terms of the proposed compliance order associated with Items 2, 4 and 11,
Respondent has taken the following actions to fulfill the terms of the proposed compliance order:
As proposed for Item 2, Respondent has developed a list of all relevant county sheriff
departments, county fire departments, county emergency managers, and public officials
57 Violation Report at 23. See In the Matter of Belle Fourche Pipeline Co., Final Order, CPF No. 5-2004-5010, at 5
(Dec. 11, 2006).



25
requiring liaison. Respondent also became a member of the Wyoming Pipeline
Association, which is a consortium of pipeline operators with a mission of improving
public awareness including liaison with local responders.
As proposed for Item 4, Respondent has installed a pressure recording device at the
Guernsey pump station.
As proposed for Item 11, Respondent has completed an API Standard 653 Internal
Inspection of the Sussex diesel breakout tank.
Accordingly, since compliance has been achieved with respect to these violations, the
compliance terms are not included in this Order.
With regard to the proposed compliance order associated with Item 10, BFPL contended in its
Response that “certain alarms have been installed and are being tested,” but provided no further
explanation or documentation at the hearing or in its Brief that the company has inspected and
tested the high level alarms specified in the proposed compliance order.58
With regard to the proposed compliance order associated with Item 12, BFPL did not provide
any documentation of additional protection installed at the Donkey Creek Pump Station, Sussex
Pump Station, and Sussex Breakout Tank.
With regard to the proposed compliance order associated with Item 13, BFPL contended in its
Response and Brief that it had already performed a CIS in June-July 2009 and determined based
on that study that no detrimental stray currents are impacting its facilities in the specified area.
After reviewing the referenced study, it appears that the purpose of the CIS was to evaluate
cathodic protection levels and areas of coating damage. In Respondent’s Exhibit 7, its third-
party contractor states that it “was contracted to perform a close interval On/Off cathodic
protection survey on the 12[-inch] Belle Fourche Pipeline as part of Belle Fourche Pipeline’s
ongoing integrity program.” It is not evident from the record that the CIS constituted an
interference study.
With regard to the proposed compliance order associated with Item 14, BFPL contended in its
Response that “BFPL has initiated an investigation to determine if there are any additional steps
necessary to mitigate the effects of internal corrosion,
” but provided no further explanation or
documentation at the hearing or in its Brief regarding such an investigation.
59
Under 49 U.S.C. § 60118(a), each person who engages in the transportation of hazardous liquids
by pipeline or who owns or operates a hazardous liquid pipeline facility is required to comply
with the applicable safety standards established under chapter 601. Pursuant to the authority of
49 U.S.C. § 60118(b) and 49 C.F.R. § 190.217, Respondent is ordered to take the following
actions to ensure compliance with the pipeline safety regulations applicable to its operations:
58 Response at 12.
59 Response at 16.



26
1. With respect to the violation of § 195.428(d) (Item 10), BFPL must inspect and test the
high level alarms on the following tanks: Sussex Pump Station Breakout Tank (BOT);
Davis Station (Tank 74) BOT; and Hawk Point Terminal BOT.
2. With respect to the violation of § 195.436 (Item 12), BFPL must install adequate
protection from vandalism and unauthorized entry for the Donkey Creek Pump Station,
Sussex Pump Station, and Sussex Breakout Tank. The protection must consist of the
following, unless BFPL can demonstrate an alternative method of protection that
achieves the same or greater level of safety and security: security fencing that is a
minimum of six feet high and includes a minimum of three strands of barbed wire above
the fencing with appropriate warning signs and operator contact information installed on
the fencing, and with gates that can be locked.
3. With respect to the violation of § 195.577(a) (Item 13), BFPL must perform an
interference study on the Donkey Creek Pipeline between Guernsey station and Ft.
Laramie station and remediate any stray currents that are found.
4. With respect to the violation of § 195.579(a) (Item 14), BFPL must conduct an
investigation to determine if crude oil transported through its pipeline system has the
ability to cause internal corrosion. If the results of the investigation warrant, BFPL must
develop and follow procedures for appropriate remedial actions to mitigate the
occurrence of internal corrosion.
5. BFPL must complete the actions required by this Compliance Order and submit
documentation demonstrating compliance within 60 days following receipt of the Final
Order. Documentation of compliance must be submitted to the Director, Western
Region, Pipeline and Hazardous Materials Safety Administration, 12300 W. Dakota Ave.
#110, Lakewood, CO 80228. Documentation may be submitted in an electronic format
when feasible.
6. It is requested that BFPL maintain documentation of the safety improvement costs
associated with fulfilling this Compliance Order and report the total cost to the Director
in two categories: (a) total cost associated with preparation and revision of plans and
procedures, and performance of studies and analyses; and (b) total cost associated with
physical changes, if any, to the pipeline infrastructure, including replacements and
additions.
The Director may grant an extension of time to comply with any of the required items upon a
written request timely submitted by the Respondent demonstrating good cause for an extension.
Failure to comply with this Order may result in administrative assessment of civil penalties not
to exceed $100,000 for each violation for each day the violation continues or in referral to the
Attorney General for appropriate relief in a district court of the United States.
WARNING ITEM
In addition, with respect to Item 7, the Notice alleged a probable violation of Part 195 and
specifically considered this to be a warning item. The warning was for:



27
49 C.F.R. § 195.412(a) (Item 7) – Respondent allegedly failed to inspect the right-of-way
of its Bicentennial pipeline in Montana at the required intervals between March 24 and
April 21, 2008, and between June 4 and July 5, 2008. Specifically, the Notice alleged
Respondent had aerial inspection records for the Bicentennial pipeline during those
periods, but the records indicated the Montana portion had not been flown.
If OPS finds this issue in a subsequent inspection, Respondent may be subject to future
enforcement action.
Under 49 C.F.R. § 190.215, Respondent has a right to submit a Petition for Reconsideration of
this Final Order to the Associate Administrator for Pipeline Safety, 1200 New Jersey Avenue,
SE, East Building, 2nd Floor, Washington, DC 20590. A petition must be received within 20
days of Respondent’s receipt of the Final Order. The petition must contain a brief statement of
the issue(s) and meet all other requirements of 49 C.F.R. § 190.215. The filing of the petition
automatically stays the payment of any civil penalty assessed. All other terms of the order,
including any required corrective action, shall remain in full force and effect unless the Associate
Administrator, upon request, grants a stay. The terms and conditions of this Final Order are
effective upon service in accordance with 49 C.F.R. § 190.5.
___________________________________ __________________
Jeffrey D. Wiese Date Issued
Associate Administrator
for Pipeline Safety

## Provenance

- Official: Yes
- Source: <https://primis.phmsa.dot.gov/enforcement-data/case/520095042>
- Source ID: `phmsa-enforcement`
- SHA-256: `bb5ebdbf4892cc20eb1fc67c1a202e4fbe26b2985265ce62181b68efdd3dc543`
- Retrieved: 2026-08-20T04:44:44.458Z
- Exported: 2026-08-22T10:35:12.436Z
- Document slug: `phmsa-enforcement-520095042`

### Source metadata

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