# ALYESKA PIPELINE SERVICE CO — Warning Letter

- **operation:** document
- **citation:** CPF 520180013W
- **title:** ALYESKA PIPELINE SERVICE CO — Warning Letter
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2018-12-27
- **effective on:** Not available
- **summary:** CLOSED warning letter citing 192.479(a), 192.479(b), 192.605(a), 192.709(c), 192.807(a), 192.907(a), 192.919(b), 192.919(c).
- **machine formats:** - **json:** https://regulus.evalyn.ai/document/phmsa-enforcement-520180013w.json
- **markdown:** https://regulus.evalyn.ai/document/phmsa-enforcement-520180013w.md
- **app url:** https://regulus.evalyn.ai/document/phmsa-enforcement-520180013w
- **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/520180013W
**body:**

Warning Letter involving ALYESKA PIPELINE SERVICE CO. PHMSA's enforcement data identifies the cited regulations as 192.479(a),  192.479(b),  192.605(a),  192.709(c),  192.807(a),  192.907(a),  192.919(b),  192.919(c). The case was opened on 2018-12-27 and is reported as closed as of 2018-12-27. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

520180013W_Operator Response to Notice_01282019.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520180013W/520180013W_Operator%20Response%20to%20Notice_01282019.pdf

520180013W_Warning Letter_12272018.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520180013W/520180013W_Warning%20Letter_12272018.pdf

520180013W_Warning Letter_12272018_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520180013W/520180013W_Warning%20Letter_12272018_text.pdf

520180013W_Warning Letter_12272018_text.pdf

WARNING LETTER
CERTIFIED MAIL - RETURN RECEIPT REQUESTED
December 27, 2018
Mr. Thomas Barrett
President and CEO
Alyeska Pipeline Service Company
PO Box 196660
Anchorage, AK 99519
CPF 5-2018-0013W
Dear Mr Barrett:
On multiple occasions between April 24, 2017 and March 16, 2018, a representative of the
Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety
(OPS), pursuant to Chapter 601 of 49 United States Code (U.S.C.), inspected your Fuel Gas
Pipeline between Pump Stations 1 and 4, and reviewed records and procedures in Anchorage,
Alaska.
As a result of the inspection, it is alleged that you have committed probable violations of the
Pipeline Safety Regulations, Title 49, Code of Federal Regulations (CFR). The items inspected
and the probable violation(s) are:
1. § 192.479 Atmospheric corrosion control: General.
(a) Each operator must clean and coat each pipeline or portion of pipeline that is
exposed to the atmosphere, except pipelines under paragraph (c) of this section.
(b) Coating material must be suitable for the prevention of atmospheric corrosion.
The Operator failed to properly coat each pipeline that is exposed to the atmosphere. Several
above ground valve stations had exposed inadequate coating, particularly at soil-to-air interfaces.



According to the Operator, the Atigan River Bridge span over the river has a “coating system”
comprised of a Fusion Bonded Epoxy (FBE) coating and a tape wrap that protects the FBE
coating from ultraviolet rays. The tape coating is in decrepit condition, peeling off
approximately 50% of the pipeline, and, therefore, exposing the once underlying FBE coating to
damaging ultraviolet rays. Suitable coating must be applied to prevent atmospheric corrosion.
Tape wrap is not considered suitable.
2. § 192.605 Procedural manual for operations, maintenance, and emergencies
(a) General. Each operator shall prepare and and follow for each pipeline, a
manual of written procedures for conducting operations and maintenance activities
and for emergency response. For transmission lines, the manual must also include
procedures for handling abnormal operations. The manual must be reviewed and
updated by the operatorat intervals not exceeding 15 months, but at least once each
calendar year. This manual must be prepared before operations of a pipeline
system commence. Appropriate parts of the manual must be kept at locations
where operations and maintenance activities are conducted.
The Operator failed to following their written operations and maintenance procedure for annual
testing of the compressor station gas detection system. The Operator's procedure FG-78
Operating, Maintenance and Emergency Plans for the Fuel Gas Pipeline for testing of the
compressor station gas detection system is labeled “Annual” and states that it is a “procedure for
Annual testing.” Records show tests were performed on December 12, 2015 and February 4,
2017. Contrary to the Operator’s procedure no testing was conducted in 2016, therefore the
operator failed to following their written operations and maintenance procedure.
3. § 192.605 Procedural manual for operations, maintenance, and emergencies.
(a) General. Each operator shall prepare and follow for each pipeline, a manual of
written procedures for conducting operations and maintenance activities and for
emergency response. For transmission lines, the manual must also include
procedures for handling abnormal operations. This manual must be reviewed and
updated by the operator at intervals not exceeding 15 months, but at least once each
calendar year. This manual must be prepared before operations of a pipeline system
commence. Appropriate parts of the manual must be kept at locations where
operations and maintenance activities are conducted.
The Operator did not review and update its operations, maintenance and emergency procedures
each calendar year not exceeding 15 months. § 192.605(a) requires that an operator do a review,
not exceeding 15 months, but at least once a calendar year, of operations and maintenance
procedures and emergency procedures. The Operator’s document FG78 Operating,
Maintenance, and Emergency Plans for the Fuel Gas Line has a revision history without a 2014
calendar year review. The Operator’s System Integrity Monitoring Procedures MP166 2.02 Fuel
Gas Line Monitoring has a large gap on the revision history between 2009 and 2013.
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4. § 192.709 Transmission lines: Record keeping.
Each operator shall maintain the following records for transmission lines for the
periods specified:
…
(c) A record of each patrol, survey, inspection, and test required by subparts L and
M of this part must be retained for at least 5 years or until the next patrol, survey,
inspection, or test is completed, whichever is longer.
The Operator failed to keep proper records for emergency valve testing over a several year
period. During the inspection, PHMSA requested 2014-2016 DOT annual valve records for four
(4) valves: 2014-2016 MGV-2, 00-V159(FG), 15-V400(FG), and MGV-9. None of the
requested documents were provided. The Operator only provided a 2016 record for MGV-2 and
the 2015 and 2016 records for MGV-9. Furthermore, the provided records failed to adequately
document proper inspection and partial operation of emergency transmission line valves as some
of the records were undated.
5. § 192.807 Recordkeeping.
Each operator shall maintain records that demonstrate compliance with this
subpart.
(a) Qualification records shall include:
(1) Identification of qualified individual(s);
(2) Identification of the covered tasks the individual is qualified to perform;
(3) Date(s) of current qualification; and
(4) Qualification method(s).
The Operator failed to have qualified individuals performing an ongoing covered task. The
Operator has a covered task labeled PC-PIT/027 which is an active and ongoing task involving
testing of Emergency Shutdown Devices for the fuel gas line. Operator’s records revealed that,
although the covered task was ongoing, no personnel were qualified for the task.
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6. § 192.907 What must an operator do to implement this subpart?
(a) General. No later than December 17, 2004, an operator of a covered pipeline
segment must develop and follow a written integrity management program that
contains all the elements described in § 192.911 and that addresses the risks on each
covered transmission pipeline segment. The initial integrity management program
must consist, at a minimum, of a framework that describes the process for
implementing each program element, how relevant decisions will be made and by
whom, a time line for completing the work to implement the program element, and
how information gained from experience will be continuously incorporated into the
program. The framework will evolve into a more detailed and comprehensive
program. An operator must make continual improvements to the program.
Alyeska Pipeline Service Company (APSC) failed to develop and follow a written integrity
management program within one year from the date of identification of the initial High
Consequence Area (HCA) and associated covered pipeline segment on the Fuel Gas Line.
Alyeska does appear to be in compliance with this requirement but was not before December 11,
2013.
APSC began reporting HCA mileage to PHMSA for their Fuel Gas Line in 2009, and has
continued to do so on its annual reports as required by § 191.17. However, APSC did not
develop its baseline integrity management plan for the segment of the Fuel Gas Line that was
first reported in 2009 as being located within a HCA until December 11, 2013. APSC’s initial
written integrity management program (IM-246, Fuel Gas Line Integrity Management Plan for
High Consequence Area Covered Segments, Rev. 0) is dated December 11, 2013.
The regulation at issue imposes a continuing obligation on operators to follow a baseline
integrity management plan, one which the regulation requires to continually evolve based on
information gained from experience. Further, § 192.907(a) requires that an operator develop and
follow a written integrity management program for a covered pipeline segment located within a
HCA, and that the written integrity management program must contain all the elements described
in § 192.911. Pursuant to § 192.911, an integrity management program must contain several
elements, including a baseline assessment plan. Pursuant to § 192.905(c), a newly identified
HCA must be incorporated into a baseline assessment plan within one year from the date the
HCA was identified. Other required elements of an integrity management program must be
utilized in the development of a baseline assessment plan, including threat identification, data
gathering and integration, and risk assessment. As such, an operator must develop and follow a
written integrity management program for covered pipeline segment(s) located within a HCA
within one year from the date of which the pipeline’s initial HCA was identified, and
continuously follow and update the baseline assessment plan.
APSC reported HCA mileage to PHMSA for the Fuel Gas Line continuously since 2009.
Conservatively assuming that the initial HCA on the Fuel Gas Line was identified on December
31, 2009, APSC was required to develop and follow a written integrity management program
4



that contains all the elements described in § 192.911 and addresses the risks on each covered
transmission pipeline segment by December 31, 2010. APSC's initial written integrity
management program (Integrity Management Plan IM-246, Rev. 0) is dated December 11, 2013,
approximately 4 years after the identification of the Fuel Gas Line’s initial HCA and covered
pipeline segment, or approximately 3 years after the required date for development of a written
integrity management program for the covered pipeline segment. Once the initial plan is
developed, § 192.907(a) requires the operator to continuously modify and update the plan.
APSC was in continuous violation of the regulation from at least December 31, 2010 until
December 11, 2013, when it first developed its integrity management plan for the covered
segment.
7. § 192.919 What must be in the baseline assessment plan?
An operator must include each of the following elements in its written baseline
assessment plan:
…
(b) The methods selected to assess the integrity of the line pipe, including an
explanation of why the assessment method was selected to address the identified
threats to each covered segment. The integrity assessment method an operator uses
must be based on the threats identified to the covered segment. (See §192.917.) More
than one method may be required to address all the threats to the covered pipeline
segment;
The Operator failed to give details as to why specific in-line inspection tools and testing were
selected to address identified threats. The Operator’s Baseline Assessment Plan specifies
assessment methods, but does not explain why the tools were selected for identified threats to the
covered segment.
8. § 192.919 What must be in the baseline assessment plan?
An operator must include each of the following elements in its written baseline
assessment plan:
…
(c) A schedule for completing the integrity assessment of all covered segments,
including risk factors considered in establishing the assessment schedule;
The Operator’s Baseline Assessment Plan does not contain a schedule for completing further
assessment activities. The Operator’s IM-246 Fuel Gas Line Integrity Management Plan dated
Dec 15, 2015 contains two sections regarding the Baseline Assessment Plan: Section 7 and
Appendix C2. Neither section provides a schedule for completing the assessment activities as
required by 192.919(c).
5



Under 49 U.S.C. § 60122 and 49 CFR § 190.223, you are subject to a civil penalty not to exceed
$209,002 per violation per day the violation persists, up to a maximum of $2,090,022 for a
related series of violations. For violations occurring prior to November 2, 2015, the maximum
penalty may not exceed $200,000 per violation per day, with a maximum penalty not to exceed
$2,000,000 for a related series of violations. 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 correct the
item(s) identified in this letter. Failure to do so will result in Alyeska Pipeline Service Company
being subject to additional enforcement action.
No reply to this letter is required. If you choose to reply, in your correspondence please refer to
CPF 5-2018-0013W. 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).
Sincerely,
Chris Hoidal
Acting Director, Western Region
Pipeline and Hazardous Materials Safety Administration
cc: PHP-60 Compliance Registry
PHP-500 J. Owens/T. Johnson (# 155098)
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