# PHILLIPS 66 PIPELINE LLC — Notice of Probable Violation

**Citation:** CPF 420145011  
**Type / status:** enforcement / historical  
**Agency:** Pipeline and Hazardous Materials Safety Administration  
**Effective:** Not stated  
**Published:** 2014-05-13

CLOSED notice of probable violation citing 195.402(a), 195.432(b), 195.452(b), 195.452(b)(5), 195.452(f)(1), 195.452(h)(2), 195.505(a), 195.505(b).

## Document text

Notice of Probable Violation involving PHILLIPS 66 PIPELINE LLC. PHMSA's enforcement data identifies the cited regulations as 195.402(a),  195.432(b),  195.452(b),  195.452(b)(5),  195.452(f)(1),  195.452(h)(2),  195.505(a),  195.505(b). The case was opened on 2014-05-13 and is reported as closed as of 2018-05-14. Proposed civil penalty: $175,300. Assessed civil penalty: $175,300. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

420145011_Closure Letter_05102018_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145011/420145011_Closure%20Letter_05102018_text.pdf

420145011_Closure Letter_05142018.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145011/420145011_Closure%20Letter_05142018.pdf

420145011_Final Order_09112015.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145011/420145011_Final%20Order_09112015.pdf

420145011_Final Order_09112015_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145011/420145011_Final%20Order_09112015_text.pdf

420145011_NOPV PCP PCO_05132014.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145011/420145011_NOPV%20PCP%20PCO_05132014.pdf

420145011_NOPV PCP PCO_05132014_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145011/420145011_NOPV%20PCP%20PCO_05132014_text.pdf

420145011_Operator Response to Notice_06132014.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145011/420145011_Operator%20Response%20to%20Notice_06132014.pdf

420145011_Closure Letter_05142018.pdf

U.S. Department
8701 S. Gessner, Suite 630
of Transportation
Houston, TX 77074
Pipeline and
Hazardous Materials Safety
Administration
CERTIFIED MAIL - RETURN RECEIPT REQUESTED
May 14, 2018
Mr. Todd Denton
President
Phillips 66 Pipeline LLC
1075 W Sam Houston Pkwy
N. Suite 200 N812-03
Houston, TX 77043
CPF 4-2014-5011
Dear Mr. Denton:
On September 11, 2015, the Pipeline and Hazardous Materials Safety Administration (PHMSA)
issued to Phillips 66 Pipeline LLC 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.
matters involved in this case. Thank you for your cooperation in this matter.
Accordingly, this case is now closed and no further action is contemplated with respect to the
Sincerely,
Mary L. McDaniel, P.E
Director, Southwest Region
Office of Pipeline Satety
Pipeline and Hazardous Materials Safety Administration

420145011_NOPV PCP PCO_05132014_text.pdf

NOTICE OF PROBABLE VIOLATION
PROPOSED CIVIL PENALTY
and
PROPOSED COMPLIANCE ORDER
CERTIFIED MAIL - RETURN RECEIPT REQUESTED
May 13, 2014
Mr. Todd Denton
President
Phillips 66 Pipeline, LLC
3010 Briarpark Drive
Houston, TX 77042
CPF 4-2014-5011
Dear Mr. Denton:
On multiple occasions between April and November 22, 2013, representatives of the Pipeline and
Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), pursuant to
Chapter 601 of 49 United States Code were onsite and inspected portions of Phillips 66 Pipeline LLC
(Phillips) pipeline system located in Texas and Oklahoma.
As a result of the inspections, it appears that you have committed probable violations of the Pipeline
Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and the probable
violation(s) 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 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.



Phillips did not follow their written atmospheric storage tank level alarm policy. P66PL-TPO-4001:
Atmospheric Storage Tank Level Alarm Policy (Rev. 7 – Effective Date: 2012-07-09), Section 7 -
Inspection and Testing (Quarterly) states:
“New systems are designed fail safe and alarm upon electrical failure. Steps should be taken
to ensure existing systems perform in the same manner where possible. Level alarming
systems shall be visually inspected, have an electronic integrity test performed and be
functionally tested each quarter. These functions shall include the following: Point-to-point
verification will be completed for safety-related points by the field technician in contact
with the Controller for that pipeline as part of the repair or calibration using established
maintenance procedures. Document the name of the Controller on the form associated with
this procedure. The results of these point-to-point verifications will be retained in
accordance with current practice for these calibrations.”
While reviewing records associated with the overfill protection on Tanks 1201, 1202, 1501, 2101,
2301, 2302, 2303, 2304 and 2305, PHMSA noted the tanks were last inspected on 7/25/2012 and
again on 1/29/2013. Phillips failed to provide documentation showing these devices were inspected
during the 4th quarter of 2012.
Phillips, during their 1/29/2013 inspection, failed to document that the company conducted an alarm
test for tank 1202. Also, during the third and fourth quarters of 2012 and the first and second quarter of
2013, P66PL failed to document the name of the controller on the level alarm inspection and testing
report required by their own procedure.
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.
Phillips did not follow their written cathodic protection testing procedure. P66PL, MPR
6018:Cathodic Protection Testing, Rev. 9 (Effective Date: 2012-03-27), section 7.3.4.1 states:
“For the annual structure to soil survey, conduct a minimum of four (4) SSP readings at
evenly spaced locations around the perimeter of each aboveground storage tank. The
structure-to-soil measurements shall be taken adjacent to the tank ringwall and the hook-up
to the tank floor shall be on the chime weld extension, on a lug on the tank shell
specifically for SSP readings or on another readily accessible location on the tank.”
2



While reviewing Phillips’ 2011, 2012, and 2013 annual cathodic protection survey records associated
with the PHMSA jurisdictional breakout tanks # 201 and 202, PHMSA noted that the company
conducted only one structure to soil potential reading, instead of the required four readings at evenly
spaced locations around the perimeter of tanks. When PHMSA raised the concern, the Phillips
corrosion technician stated that Phillips had never taken four readings because these tanks are smaller
diameter tanks and thus, it was not required. Upon further review, PHMSA found the aforementioned
procedure and brought it to the company’s attention. The technician agreed and updated the Phillips
records accordingly on June 25, 2013. During the PHMSA field inspection, adequate CP levels were
noted.
3. §195.505 Qualification program.
Each operator shall have and follow a written qualification program. The program shall
include provisions to:
(a) Identify covered tasks;
(b) Ensure through evaluation that individuals performing covered tasks are qualified;
Phillips failed to ensure through evaluation that employees were qualified to perform covered tasks on
29 separate occasions. During the inspection, the following was identified:
While reviewing records associated with the Overfill Protection equipment on the 17 DOT regulated
tanks in Pasadena, TX, PHMSA noted that Phillips failed to ensure through evaluation that an
employee was qualified to perform a covered task. Specifically, task BT6023.1: Field Inspection and
Testing of Overfill Protection Devices on Aboveground Breakout Tanks/Vessels. A Phillips employee
performed the task on April 26, 2013. PHMSA reviewed the qualification records for this individual,
and the records indicated his qualification was not current for this covered task. According to Phillips,
the individual was a new hire and he was not qualified on covered task BT6023.1 until April 30, 2013.
While reviewing records associated with the Annual Tank Inspections for 11 tanks located in
Pasadena, TX, PHMSA noted that Phillips failed to ensure, through evaluation, that an employee was
qualified to perform a covered task. Specifically task BT2810 - Annual Visual Inspection of
Aboveground Storage Tanks Greater than 10,000 gallons. Phillips employee conducted annual tank
inspections on 11 separate days for the aforementioned tanks. PHMSA reviewed the qualification
records for this individual, and the records indicated that his qualification records were not current for
this covered task. The individual was last qualified on this covered task on January 14, 2010. The
Phillips Operator Qualification Covered Task Reevaluation Frequency, BT2810, requires subsequent
qualification at intervals of three years. Therefore, this qualification expired on or about January 14,
2013. At the time of the inspection, Phillips failed to provide documentation indicating that an
employee was qualified prior to performing a covered task during the period of January 17-28, 2013.
This individual was re-qualified on 3/4/2013.
While reviewing records associated with PI Form - Span and Exposed Piping Inspection Reports,
PHMSA noted that Phillips failed to ensure through evaluation that two employees were qualified to
perform a covered task. Specifically task CC6020 - Inspect Span and Exposed Pipe. Two Phillips
employees conducted a Span and Exposed pipe inspection on 2/16/2010. PHMSA reviewed the3



qualification records for these individuals, and the records indicated their qualification records were
not current for this covered task. One individual was not qualified for this task and the other individual
was qualified on 4/13/2010.
If the aforementioned covered tasks; BT6023.1, BT2810 and CC6020 are performed by a non-
qualified individual, Phillips' Operator Qualification, Active Covered Task List & Span of Control,
effective Date: 03/18/2013, Version Number: 12.0, requires a span of control of a one to
one. According to the inspection documentation provided by Phillips, a qualified employee was not
present to observe or direct these individuals at the work site.
4. §195.432 Inspection of in-service breakout tanks.
(b) Each operator must inspect the physical integrity of in-service atmospheric and low-
pressure steel aboveground breakout tanks according to API Standard 653 (incorporated
by reference, see § 195.3). However, if structural conditions prevent access to the tank
bottom, the bottom integrity may be assessed according to a plan included in the
operations and maintenance manual under § 195.402(c)(3).
Phillips failed to consider the bottom side corrosion rate when determining the internal inspection
interval in accordance with API Standard 653 (incorporated by reference, see § 195.3).
Tank #1301 was constructed in 1972. It had previously been inspected and API 653 was applied in
1994 for this tank, but documentation was not available that established an internal corrosion rate for
the tank bottom. Based upon the lack of information, API 653 processes would consider the corrosion
rate as unknown, and the maximum internal inspection interval to be 10 years. This set the first
internal inspection for Tank #1301 to occur in 2004.
On January 16, 2004, Phillips performed an internal inspection on Tank # 1301. The inspection report
for Tank #1301, dated January 16, 2004, indicated reporting criteria was set by Phillips at 0.180 inch
or less remaining thickness for the tank bottom plates. Three topside corrosion pits (Plat No. 63A, 48A
and 48B) and one bottom-side corrosion pit (Plat No.56A) were identified during this inspection
(Reference Table A-Bottom Reduction, section 6 of this report). Upon reviewing this table, PHMSA
noted, the minimum thickness remaining of 0.180, 0.180, 0.165 and 0.170 inch for plat 63A, 48a, 48B
and 56A, respectively. Of these four corrosion pits, Phillips repair documentation showed only two
anomalies were repaired and Minimum thickness for tank floor plate, API 653 Section 2.4.7
calculation sheet shows 3 topside and one soil side pitting repaired). Thus two reports are
contradicting each other.
API 653 Section 6.4.2 describes the method for establishing the maximum initial and subsequent
inspection intervals for internal inspections. Section 6.4.2 requires the calculation of the internal
inspection intervals in accordance with Section 4.4.5 providing the owner and operator of breakout
tanks obtained data on the thickness and condition of the tank bottom during an internal inspection.
An assumption of effective cathodic protection for the tank bottom side is allowed by API 653, which
then sets the soil side corrosion rate of the tank bottom plate to zero (0). However, if historic corrosion
has taken place, this is not a sufficiently conservative assumption, and the remaining unrepaired pits
4



should be used to calculate the bottom side corrosion rate as specified in API 653. If bottom side
corrosion has occurred, it is not appropriate to assume a zero corrosion rate for the tank plate soil side
in the calculation of the future inspection interval. The assumption of a zero (0) corrosion rate is
inconsistent with the application of API 653.
Phillips uses a program to determine the next internal inspection date using the formula from API 653,
and inputs from the inspection report. There are no accompanying procedures that are used by the
Phillips to establish when it is appropriate to assume that cathodic protection (CP) is effective, and the
corrosion rate can be effectively ignored in the re-inspection interval calculation. PHMSA noted that
Phillips used a corrosion rate of zero for UPr in the inspection interval calculation. This value allowed
the re-inspection interval to be set at the maximum interval of 20 years. With UPr set equal to zero (0),
Phillips set the next internal inspection date for January 16, 2024. API 653 defines UPr as the
maximum rate of corrosion on the bottom side of the tank bottom plate. Instructions state to calculate
the corrosion rate, use the minimum remaining thickness after repairs. For effective CP, UPr may be
set to zero (0).
Since corrosion had occurred on the tank bottom side, it was not appropriate to assume effective CP, or
use a corrosion rate of zero (0). Using the data obtained from the inspection report, and assuming a
linear corrosion rate based upon the age of the tank, PHMSA requested Phillips to input “No” into the
program for effective CP and use a value for UPr set equal to actual corrosion growth rate in inches per
year. These calculations yielded the next internal inspection date of May 4, 2016, significantly less
than 20 years.
Based upon these observations, PHMSA determined that Phillips failed to correctly demonstrate that it
had established a valid rate of corrosion on the bottom side of tank 1301, and did not have sufficient
information to assume a corrosion growth rate of zero in calculating its inspection interval.
5. §195.452 Pipeline integrity management in high consequence areas
(h) What actions must an operator take to address integrity issues?
(2) Discovery of condition. Discovery of a condition occurs when an operator has
adequate information about the condition to determine that the condition presents a
potential threat to the integrity of the pipeline. An operator must promptly, but no later
than 180 days after an integrity assessment, obtain sufficient information about a
condition to make that determination, unless the operator can demonstrate that the 180-
day period is impracticable
Phillips failed to declare discovery of a condition within 180 days despite the availability of the vendor
reports to make such determinations.
On October 11, 2009, Phillips ran an NDT UT tool for the WT-80 pipeline between Slaughter and MP
137. Subsequently, Phillips received a preliminary report for this run, which reported four “Company
Priority Criteria” features that met the criterion of > 160 mils in depth. Phillips received the final
report on April 7, 2010, which was 2 days before the IMP discovery deadline (180 days). Phillips
claimed that the vendor’s final report submitted on April 7, 2010, did not contain adequate information5



about the condition of this pipeline to determine if a potential threat to the integrity of the pipeline
exists. Phillips took until April 16, 2010, which is 7 days past the IMP discovery deadline to load the
final report data for analysis.
While Phillips was reviewing the tool run data in CPL-AID, they noted one anomaly was in an HCA
at Station 383050 and was determined to be an IE 3 Priority (Anomaly that is in the judgment of the
person designated by the operator to evaluate the assessment result required immediate action. Cracks,
SCC, or HIC indications called by an ILI vendor with criteria as follows: (E3) Cracks with a calculated
predicted Burst Pressure (Burst) < MAOP at the anomaly location). Phillips did not limit the pressure
at this anomaly site to 625 psi or less until 4/28/2010.
Phillips Integrity Management Program, Section 5.4.1: Process for Assessment Results Review states:
“When results are received in the form of Final Report, the INGRITY ENGINEER evaluates
the data and charts according to IEP 2.03 ILI Assessment Procedure within 30 business days
from the receipt of report.”
A review of IEP 1.03 – Reporting Requirements for Pipeline In-Line Inspection Procedure revealed
that Phillips allows 180 days for the Final Report to NDT Global vendor who runs the UT-UC tool.
Thus, Phillips procedure provides 180 days plus 30 business days to evaluate the data. The operator’s
anomalous condition discovery process is inconsistent with the regulatory requirement.
It was Phillips, while analyzing the vendor’s data in final report noted a threat to the integrity of the
pipeline, but not until 4/28/2010, which was beyond 180 days. A vendor's failure to highlight an
immediate repair condition in the Executive Summary or "feature summary listings" does not excuse
Phillips’ failure to discover the immediate condition within the 180-day timeframe.
6. § 195.452 (b) What program and practices must operators use to manage pipeline integrity?
Each operator of a pipeline covered by this section must:
(1) Develop a written integrity management program that addresses the risks on each
segment of pipeline in the first column of the following table not later than the date in the
second column:
(5) Implement and follow the program.
Phillips failed to make the appropriate changes to and follow their Integrity Management Plan to insure
that the manual is effective. Phillips Integrity Management Program, Section 5 Inspection and Repair,
Pipeline Maintenance and Leak Report, Section 5.6.3 states:
“P66PL uses the Pipeline Maintenance and Leak Report (PMLR) located in e-Forms, in
conjunction with the ILI Integrity Work List, to track the completion of repairs. O&M
Personnel complete and submit the PMLR, Form 3933, Pipeline Maintenance & Leak Report
(PMLR) and companion Form 3933B, Field Anomaly Evaluation for any of the following
tasks, and distribute them as detailed in MPR-2809, Instructions for Completing Form 3933 –6



Pipeline Maintenance & Leak Report (PMLR), and MPR-2839, Instructions for Completing
Form 3933B Field Anomaly Evaluation:
• Evaluating ILI features
Mapping receives the submitted PMLR, and then follows the workflow described in IEP 3.04
Pipeline Maintenance & Leak Report (PMLR) – Process Work Flow. This workflow describes
how the new data received is used to update the PODS database and where the hardcopy
records are stored.”
PHMSA learned that both MPR 2809 and MPR 2839 were discontinued in 2009. According to
Phillips, the eForm is a smart form and self-explanatory. Phillips last revised their IM plan (Revision
9) on July 21, 2011.
In addition, while reviewing the 2010 UT Crack Tool Okarche to Clinton data, dated 9/22/10, it was
noted that Phillips identified a total of 5 “Company Priority Criteria” conditions, based upon the
company criteria HCA & Non-HCA - Anomalous Condition Definition. Of those five, two of the
priority conditions (Station 1006239.13 and 1006232.05) were anomalies defined as IE Priority 2005C
(Cracks, SCC or HIC indications called by an ILI Vendor with criteria as follows: C) Cracks with a
calculated Predicted Burst Pressure (Burst) < MOP at the anomaly location). For these two anomalies,
Phillips made a repair with a 12' full encirclement sleeve and completed the Pipeline Maintenance and
Leak Report (PMLR)(eForm # LO-01-11-0504). Upon further review of this eForm, PHMSA learned
that the “Field Anomaly Evaluation” documentation (eForm 3933B), dated 1/20/2011, reported that the
first anomaly was 32.250 feet offset from weld # 96260, and 79.2 inches long, and, the second
anomaly was 25.17 feet offset from weld # 96260, and 43.7 inches long. Based on this information,
the anomaly should have been repaired with more than twelve (12) feet.
In the same eForm, the “Inline Inspection Tool Correlation NDE Report” dated 1/20/2011 reported that
a total axial length of these two anomalous conditions from start to end (start of indication 24.31 and
35.60 end of indication) is 11.29 feet and, as a result, a 13.10 feet length of pipe was examined. But
based on this report, 12 feet of type “B” sleeve was installed between upstream station # 10062+63.13
and downstream station # 10062+75.13.
Two separate forms for the same location contradict each other. PHMSA verified Phillips’ PODS
Database on 11/22/2013. The PODS Database showed 12 feet of full wrap was utilized at this location.
It appears that Phillips O&M personnel failed to accurately complete the companion form 3933 B of
PMLR during their field anomaly evaluation on 1/20/2011. In addition, the Supervisor, the Integrity
Group and Mapping, failed to review the “Anomaly Evaluation”- for thoroughness on 2/14/2011,
2/21/2011 and 4/15/2011, respectively. Phillips failed to correct this issue until PHMSA brought it to
the company’s attention.
During the inspection, PHMSA noted several maintenance and construction related eForms throughout
the SW Region were found incomplete. Phillips completed these forms only after PHMSA brought to
the attention of the company.
7



7. §195.452 Pipeline integrity management in high consequence areas.
(f) What are the elements of an integrity management program? An integrity
management program begins with the initial framework. An operator must continually
change the program to reflect operating experience, conclusions drawn from results of the
integrity assessments, and other maintenance and surveillance data, and evaluation of
consequences of a failure on the high consequence area. An operator must include, at
minimum, each of the following elements in its written integrity management program:
(1) A process for identifying which pipeline segments could affect a high consequence
area;
Phillips did not properly identify all segments that could affect an HCA. While reviewing Phillips'
TranMap10, which manages and communicates information regarding HCA boundaries, PHMSA
noted that Line EZ at Hwy 183 crossing in Austin (East side is Creedmoor Street, Area Pilot Knob)
appeared to be in an HCA. When PHMSA inquired further, Phillips responded that an older revision of
the NPMS (based on 2000 census data) did not identify this area as an HCA. Phillips conducted the
first HCA analysis for this area during the 3rd Quarter of 2006 and determined that it was not an HCA
area, because it was not identified as an HCA in NPMS. Phillips updated this area as an HCA on
August 28, 2013, only after the new version of NPMS (based on 2010 census data) was released in
2012. According to Phillips, since 1995, nothing has changed and the population has not grown.
Based on the aforementioned, Phillips relied solely on NPMS data and failed to look for new HCAs on
their own. The regulation does not except an operator from meeting the segment identification
requirement because data is incomplete and/or is not available on the NPMS. The operator has a
responsibility to seek and use alternative data to ensure that it has accurately identified pipeline
segments that could affect an HCA.
8. §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.
Phillips failed to follow their welding procedures and welder qualification requirements. On
September 23, 2009, P66PL ran a NDT UT crack tool on the WT-80 pipeline from Weems to
Slaughter, Texas. As a result, one of the anomalies (Station 221227.83) was repaired with a welded
sleeve on April 16, 2010. PHMSA reviewed the records associated with this repair (eForm WT-80-10-
0517) and identified that one of the two welders used for this project was qualified with ASME Section
IX on April 13, 2010. Upon further review of welder qualification record (Form GPL-106) revealed
that the actual test value for weld progression (Up/Down) was marked as Downhill. However, the
welder was qualified with an Uphill progression.
8



Phillips’ MPR 4401- Welding Procedures and Welder Qualification, Section 11.1.1 states”
“When a qualification weld for THE COMPANY is completed, the inspector or the
supervisor shall complete the Welder Qualification Record for that welder and that weld.
Refer to MPR-2811 for instructions for completing the Welder Qualification Record, P66
Form GPL-106.”
PHMSA reviewed MPR-2811 - Company Forms – Welder Qualification Record (Rev. 1 – Effective
Date: 2008-07-08) and learned that the qualified range value for both API 1104 and ASMX IX test,
must be the same as the actual test value.
Based on this review, the Phillips Certified Welding Inspector (CWI) failed to follow Phillips’
procedures to qualify the welder properly. When PHMSA raised this concern, Phillips stated, “After
reviewing Tommy’s WQR with our welding SME, he deemed that the paperwork was incorrectly
filled out. We’ve located the CWI (Darryl Ezzell) and reviewed with him the errors found with his
paperwork.” Phillips CWI updated the same document and resubmitted it (November 15, 2013) with a
welding progression actual value as “Uphill.”
9. § 195.452 (b) What program and practices must operators use to manage pipeline integrity?
Each operator of a pipeline covered by this section must:
(1) Develop a written integrity management program that addresses the risks on each
segment of pipeline in the first column of the following table not later than the date in the
second column:
(5) Implement and follow the program.
Phillips failed to follow their Integrity Management Program. P66PL-TSD-3008, Evaluation/Repair of
External/Internal Pipeline Defects and Anomalies, Rev. 1 – Effective date 2012-10-15, Section 5.1.2:
Defect Repair Requirements states:
“The company will use the repair conditions criteria listed in section 195.452(h) of DOT 195,
DOT 192.933, and Appendix A to address anomalies discovered in a High Consequence Area
(HCA) and non-High Consequence Area (non-HCA)”.
PHMSA reviewed records associated with the WT-80 pipeline TDW Magpie Combo tool run between
Slaughter and MP 137 (tool run date 5/12/2010). Philips received the final report on 7/20/10 and
discovered two anomalies on 9/27/2010 (repaired in May 2012) and three anomalies on 7/23/2010
(repaired in December 2012) due to the company criteria for non-HCA - anomalous conditions defined
per P66PL-TSD-3008. All five anomalies were reported as an IE Priority Code 1030 - Corrosion of or
along the Long Seam Weld.
Similarly, PHMSA reviewed records associated with the LO-01 pipeline TDW Magpie MFL tool run
between Buxton and Clinton (tool run date 7/6/2009). Phillips received the final report on 10/05/20099



and noted 142 anomalies (discovery date of 10/13/09). Of the 142 anomalies, nine met the company
criteria for Non-HCA anomalous condition definitions (1005C: Metal loss where SOP Pressure< MOP
at the anomaly location). All nine anomalies were repaired between February – March of 2011.
According to P66PL-TSD-3008, Revision 4 - Effective Date: 2012-10-15, repairs are required to be
made within 12 months. When PHMSA questioned why the aforementioned anomalies had not been
repaired within 12 months, Phillips advised that they combined MPR-4103 General Line and
Equipment Maintenance Evaluation/Repair of External/Internal Pipeline Defect and Anomalies (Rev.
13 – Effective Date: 2010-050-13) and GPL 513 into TSD-3008 in 2011. The previous policy (MPR-
4103) had an 18-month requirement.
Furthermore, Phillips’ Integrity Management Plan, Section 1.3.8: Management of Change states:
“Over time, changes may occur in the P66PL-operated pipeline systems, the operations of
those systems, and/or the environment surrounding those systems, that may influence how an
asset could affect an HCA. In an effort to ensure the program remains current, the IMP MOC
process ensures proper documentation, communication, and response to changes affecting the
program.
The IMP MOC effort focuses on, but is not limited to, the following key areas:
• Newly identified HCAs
• Changes to assessment plans
• Modifications to the IMP based on new information
• Changes in regulatory requirements
• Changes in operations
• Newly acquired integrity inspection data”.
While updating the aforementioned policies, Phillips did not follow their IMP MOC procedure by
failing to document changes made to assessment plans as described above. Phillips was unable to
provide the date this change went into effect.
Proposed Civil Penalty
Under 49 United States Code, § 60122, you are subject to a civil penalty not to exceed $200,000 per
violation per day the violation persists up to a maximum of $2,000,000 for a related series of
violations. For violations occurring prior to January 4, 2012, the maximum penalty may not exceed
$100,000 per violation per day, with a maximum penalty not to exceed $1,000,000 for a related series
of violations. The Compliance Officer has reviewed the circumstances and supporting documentation
involved in the above probable violation(s) and has recommended that you be preliminarily assessed a
civil penalty of $175,300 as follows:
10



Item number PENALTY
2 $45,700
3 $86,400
5 $43,200
Warning Items
With respect to items 1, 8 and 9 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). Failure to do so
may result in additional enforcement action.
Proposed Compliance Order
With respect to items 4, 5, 6, and 7 pursuant to 49 United States Code § 60118, the Pipeline and
Hazardous Materials Safety Administration proposes to issue a Compliance Order to Phillips 66
Pipeline LLC. 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. All material
you submit in response to this enforcement action may be made publicly available. If you believe that
any portion of your responsive material qualifies for confidential treatment under 5 U.S.C. 552(b),
along with the complete original document you must provide a second copy of the document with the
portions you believe qualify for confidential treatment redacted and an explanation of why you believe
the redacted information qualifies for confidential treatment under 5 U.S.C. 552(b). If you do not
respond within 30 days of receipt of this Notice, this constitutes a waiver of your right to contest the
allegations in this Notice and authorizes the Associate Administrator for Pipeline Safety to find facts as
alleged in this Notice without further notice to you and to issue a Final Order.
In your correspondence on this matter, please refer to CPF 4-2014-5011 and for each document you
submit, please provide a copy in electronic format whenever possible.
Sincerely,
R. M. Seeley
Director, Southwest
Pipeline and Hazardous Materials Safety Administration
Enclosures: Proposed Compliance Order
Response Options for Pipeline Operators in Compliance Proceedings
11



PROPOSED COMPLIANCE ORDER
Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety
Administration (PHMSA) proposes to issue to Phillips 66 Pipeline LLC a Compliance Order
incorporating the following remedial requirements to ensure the compliance of Phillips 66 Pipeline
LLC with the pipeline safety regulations:
1. 2. 3. 4. 5. 6. In regard to Item Number 4 of the Notice pertaining to Phillips failing to consider the
bottom side corrosion rate when determining the internal inspection interval in
accordance with API Standard 653, Phillips must develop procedures that clearly
identify when a corrosion rate of zero can be assumed. Phillips must also develop a
procedure that clearly identifies if an historic corrosion has occurred, and establish an
appropriate corrosion rate from the measured data in accordance with API 653. After
developing procedures, Phillips must re-evaluate their tank inspection intervals against
the revised procedure to ensure that the internal inspection intervals are calculated in
accordance with API 653 and to ensure that inspection occur prior to reaching the
minimum plate thickness necessary to ensure tank plate integrity.
In regard to Item Number 5 of the Notice pertaining to failure to declare discovery of
condition within 180 days, Phillips must amend IEP 1.03 – Reporting Requirements for
Pipeline In-Line Inspection Procedure to be consistent with the regulatory requirement
of §195.452 (h)(2).
In regard to Item Number 6 of the Notice pertaining to Phillips failing to make
appropriate changes and follow the Integrity Management Plan, Phillips must amend the
Integrity Management Plan, Section 5.6.3 and remove deleted procedures reference.
In regard to Item Number 7 of the Notice pertaining to Phillips failing to properly
identify an HCA, Phillips must amend the Integrity Management Plan to broaden the
HCA identification beyond the sole reliance on the NPMS.
Provide PHMSA with documentation that verifies completion of numbers 1 - 4 above
within 45 days following the receipt of the Final Order.
It is requested (not mandated) that Phillips 66 Pipeline LLC maintain documentation of
the safety improvement costs associated with fulfilling this Compliance Order and
submit the total to R. M. Seeley, Director, Southwest Region, Pipeline and Hazardous
Materials Safety Administration. It is requested that these costs be reported in two
categories: 1) total cost associated with preparation/revision of plans, procedures,
studies and analyses, and 2) total cost associated with replacements, additions and other
changes to pipeline infrastructure.
12

420145011_Final Order_09112015_text.pdf

September 11, 2015
Mr. C. Todd Denton
President
Phillips 66 Pipeline LLC
Pinnacle Westchase PWC 078-7150-09
3010 Briarpark Drive
Houston, Texas 77042
Re: CPF No. 4-2014-5011
Dear Mr. Denton:
Enclosed please find the Final Order issued in the above-referenced case. It makes findings of
violation, assesses a civil penalty of $175,300, and specifies actions that need to be taken by
Phillips 66 Pipeline LLC, to comply with the pipeline safety regulations. The penalty payment
terms are set forth in the Final Order. When the civil penalty has been paid and the terms of the
compliance order completed, as determined by the Director, Southwest Region, this enforcement
action will be closed. Service of the Final Order by certified mail is deemed effective upon the
date of mailing, or as otherwise provided under 49 C.F.R. § 190.5.
Thank you for your cooperation in this matter.
Sincerely,
Jeffrey D. Wiese
Associate Administrator
for Pipeline Safety
Enclosure
cc: Mr. Rodrick M. Seeley, Director, Southwest Region, OPS
Mr. Todd Tullio, Manager, Regulatory Compliance, Phillips 66 Pipeline LLC
Mr. Dave Barney, Manager, Engineering & Projects Downstream, Phillips 66 Pipeline LLC
Mr. Van Williams, General Counsel, Phillips 66 Pipeline LLC
CERTIFIED MAIL - RETURN RECEIPT REQUESTED



U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, D.C. 20590
____________________________________
)
In the Matter of )
)
Phillips 66 Pipeline LLC, ) CPF No. 4-2014-5011
a subsidiary of Phillips 66, )
)
Respondent. )
____________________________________)
FINAL ORDER
Between April 1 and November 22, 2013, 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 Phillips 66 Pipeline LLC’s (Phillips or
Respondent) facilities and records located in Texas and Oklahoma. Phillips, a wholly-owned
subsidiary of Phillips 66, operates approximately 12,000 miles of pipelines in the United States,
through which it transports raw and finished petroleum products.1
As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to
Respondent, by letter dated May 13, 2014, a Notice of Probable Violation, Proposed Civil
Penalty and Proposed Compliance Order (Notice), which also included warnings pursuant to 49
C.F.R. § 190.205. In accordance with 49 C.F.R. § 190.207, the NOPV proposed finding that
Phillips had violated 49 C.F.R. §§ 195.402, 195.505, 195.432, and 195.452, and proposed
ordering Respondent to take certain measures to correct the alleged violations. The Notice also
proposed assessing Respondent a civil penalty of $175,300 for these alleged violations. The
warning items require no further action, but the operator is warned to correct the probable
violations or face possible enforcement action.
Phillips responded to the Notice by letter dated June 13, 2014 (Response). In its Response,
Phillips stated it “elects not to contest the violations stated in the Notice,”2 but raised objections
to several of the proposed findings of violation and certain portions of the Proposed Compliance
Order, and further requested that the proposed civil penalty be reduced or eliminated.
Respondent did not request a hearing and therefore has waived its right to one.
1 Phillips 66 Pipeline, LLC, website: http://www.phillips66pipeline.com/EN/Pages/index.aspx (last visited January
12, 2015).
2 Response at 1.



CPF No. 4-2014-5011
Page 2
FINDINGS OF VIOLATION
Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 195.402(a), which states:
§ 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 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 49 C.F.R. § 195.402(a) by not following its own
cathodic-protection testing procedure, as set forth in its written procedural manual. Specifically,
the Notice alleged that Phillips violated this procedure when annually testing PHMSA-
jurisdictional breakout tanks ##201 and 202 in 2011, 2012, and 2013. According to the Notice,
Phillips allegedly conducted only one structure-to-soil potential reading per year, instead of the
required four readings at evenly-spaced locations around the perimeter of the tanks, as required
by Respondent’s procedure, Phillips 66 Pipeline, MPR 6018: Cathodic Protection Testing,
Rev. 9, Section 7.3.4.1 (Effective Date: 2012-03-07).
Respondent did not contest this allegation of violation. Accordingly, based upon a review of all
of the evidence, I find that Respondent violated 49 C.F.R. § 195.402(a) by failing to follow its
own written cathodic-protection testing procedure.
Item 3: The Notice alleged that Respondent violated 49 C.F.R. §§ 195.505(a-b), which states:
§ 195.505 Qualification program.
Each operator shall have and follow a written qualification program.
The program shall include provisions to:
(a) Identify covered tasks;
(b) Ensure thorough evaluation that individuals performing covered
tasks are qualified; . . . .
The Notice alleged that Respondent violated 49 C.F.R. §§ 195.505(a-b) by failing to ensure,
through evaluation, that certain Phillips employees were qualified to perform covered tasks on 29
separate occasions. Seventeen of these incidents took place on April 26, 2013, when Phillips
allegedly failed to ensure that the field inspection and testing of overfill protection devices on 17
PHMSA-regulated aboveground breakout tanks in Pasadena, Texas, were performed by a
properly qualified employee. An additional 11 violations allegedly occurred from January 17-
28, 2013, when Phillips failed to ensure that a qualified employee performed annual visual
inspections of 11 aboveground storage tanks greater than 10,000 gallons located in Pasadena,



CPF No. 4-2014-5011
Page 3
Texas. The last violation occurred on February 16, 2010, when Phillips allegedly failed to
ensure that two qualified employees conducted a span and exposed pipe inspection.
Respondent did not contest these allegations of violation. Accordingly, based on a review of all
of the evidence, I find that Respondent violated 49 C.F.R. § 195.505(a-b) by failing to ensure,
through evaluation, that employees were qualified to perform covered tasks on 29 separate
occasions.
Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b), which states:
§ 195.432 Inspection of in-service breakout tanks.
(a) ….
(b) Each operator must inspect the physical integrity of in-service
atmospheric and low-pressure steel aboveground breakout tanks according
to API Standard 653 (incorporated by reference, see § 195.3). However, if
structural conditions prevent access to the tank bottom, the bottom
integrity may be assessed according to a plan included in the operators and
maintenance manual under § 195.402(c)(3).
The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b) by failing to inspect the
physical integrity of in-service, aboveground breakout tanks in accordance with American
Petroleum Institute Standard 653 (API 653) (incorporated by reference in 49 C.F.R. § 195.3).
Specifically, the Notice alleged that Phillips violated Section 4.4.5.1 of API 653 by using a
bottom-side corrosion rate of zero to establish an internal corrosion rate for Tank #1301, even
after discovering evidence of corrosion on the bottom side of the tank.
Under 49 C.F.R. § 195.432(b), operators must follow Section 4.4.5.1 of API 653 in establishing
a method for calculating the minimum acceptable thickness of the bottoms of breakout tanks.3
This method is represented by the equation
MRT = (Minimum of RTbc or RTip) – Or (StPr + UPr).4
In this equation, UPr represents the maximum rate of corrosion on the bottom side of the
breakout tank; further, unless the cause of corrosion has been removed, when the bottom side of
a breakout tank has been repaired, this area must be evaluated with the corrosion rate for the
repaired area.5
3 API 653, Fourth Edition, Section 4.4.5.1 (April 2009) (“An acceptable method for calculating the minimum
acceptable bottom thickness for the entire bottom or portions thereof is as follows…”).
4 Id.
5 Id. (“NOTE 1 [to Section 4.4.5.1] For areas of a bottom that have been scanned by the magnetic flux leakage (or
exclusion) process, and do not have effective cathodic protection, the thickness used for calculating UPr must be the
lesser of the MFL threshold or the minimum thickness of corrosion areas that are not required. The MFL threshold
is defined as the minimum remaining thickness to be detected in the areas inspected. This value should be
predetermined by the tank owner based on the desired inspection interval.



CPF No. 4-2014-5011
Page 4
The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b) by failing to follow Section
4.4.5.1 of API 653. According to PHMSA, Phillips did not adhere to Section 4.4.5.1 when it
calculated the maximum corrosion rate on the repaired bottom side of breakout tank #1301, and
in doing so, failed to use the correct corrosion rate for this repaired area.
In its Response, Phillips contested the allegation of violation, asserting that the corrosion rate
used was appropriate under Section 4.4.5.1. Respondent acknowledged that it had performed a
Magnetic Flux Evaluation (MFE) on the bottom side of Tank #1301 in 2004, which showed that
the bottom side of the tank did not have uniform thickness – that one identified area had 0.180
remaining wall thickness and the rest of the tank bottom had a thickness exceeding 0.180.6
However, it argued that “the complete bottom scan showed no evidence of extensive bottom side
corrosion anomalies.”7 Therefore, Phillips decided that the existing cathodic protection system
for the tank was effective and that a bottom-side corrosion rate of zero was appropriate under
Section 4.4.5.1. However, “as an added measure of assurance,” the company installed a
0.250-inch steel patch plate over this identified area “so as to assure minimal required thickness
and cathodic protection for this area.”8
I disagree that such actions constitute compliance with API 653. First, Respondent’s records
show that it discovered evidence of corrosion on the bottom side of Tank #1301, but still
assumed a bottom-side corrosion rate of zero to determine the internal inspection corrosion rate
for the tank. As noted above, such an assumption is not allowed under Section 4.4.5.1, unless
the cause of the corrosion has been “removed.”9 Phillips installed the steel plate patch in one
identified area – but this did not remove the cause of the corrosion, nor is there any indication in
the record that Phillips took any other action to remove the cause.
10 Therefore, the methodology
used to calculate the corrosion growth rate was invalid, resulting in an excessively long interval
between inspections.
Accordingly, after considering all of the evidence, I find Respondent violated 49 C.F.R.
§ 195.432(b), by failing to inspect the physical integrity of in-service, aboveground breakout
tanks in accordance with Section 4.4.5.1 of API 653.
Item 5: The Notice alleged that Respondent violated 49 C.F.R. § 195.452(h)(2), which states:
“Areas of bottom side corrosion that are repaired should be evaluated with the corrosion rate for the repaired area
unless the cause of corrosion has been removed. The evaluation is done by using the corrosion rate of the repaired
area for UPr and adding the patch plate (if used) thickness to the term ‘minimum of RTbc or RTip.
’”) (emphasis
added).
6 Response at 6 – 7.
7 Id.
8 Id.
9 See supra note 5.
10 Response, at 6 – 7.



CPF No. 4-2014-5011
Page 5
§ 195.452 Pipeline integrity management in high consequence areas.
(a) . . .
(h) What actions must an operator take to address integrity issues?
(1) . . .
(2) Discovery of condition. Discovery of a condition occurs when an
operator has adequate information about the condition to determine that
the condition presents a potential threat to the integrity of the pipeline. An
operator must promptly, but no later than 180 days after an integrity
assessment, obtain sufficient information about a condition to make that
determination, unless the operator can demonstrate that the 180-day period
is impracticable.
The Notice alleged that Respondent violated § 195.452(h)(2) by failing to obtain sufficient
information within 180 days of an integrity assessment to determine that a condition presents a
potential threat to the integrity of the pipeline.
Specifically, the Notice alleged that on October 11, 2009, Phillips ran a “smart pig” assessment
of its WT-80 pipeline and received a preliminary report from its vendor alerting the company to
four anomalies that met the company’s own criteria for action. On April 7, 2010, two days
before the 180-day deadline under § 195.452(h)(2), Respondent received the final report from
the vendor. On April 16, 2010, or roughly a week after the 180-day deadline had passed, Phillips
allegedly loaded the tool-run data into its computer system for analysis, subsequently reviewed
the data itself, and discovered a serious anomaly that, in the company’s opinion, required
immediate action. On April 28, 2010, the company reduced the pipeline’s operating pressure at
this anomaly site to 625 psi.
In its Response, Respondent contested this allegation of violation, asserting that the 180-day
deadline was impracticable in this case. According to Phillips, the October 11, 2009 assessment
involved the use of an ultrasonic testing (UT) crack tool.11 Respondent asserted that due to the
nature of this particular tool run, it was impracticable to obtain sufficient information about the
“immediate repair” condition revealed by this run within the 180-day deadline. Phillips asserted
that none of the vendors with whom it contracted could perform a crack tool analysis, process the
results of this test, and provide these results to Phillips within the 180-day deadline.12
Respondent noted further that its vendor delivered the final report of the October 11, 2009
integrity management test on April 7, 2010 – only two days before the 180-day deadline.
Phillips claimed that after it received this document, it had to take multiple additional steps
before it could make a determination regarding a potential integrity threat, thus making
compliance impracticable.13
11 Id. at 7 – 8.
12 Id.
13 Id.



CPF No. 4-2014-5011
Page 6
I am unpersuaded by Respondent’s argument. The record reveals that on November 9, 2009,
only four weeks after Phillips ran the UT crack tool through the WT-80 pipeline, the company
received the vendor’s preliminary report, which noted four “Company Priority Criteria”
anomalies that met Phillips’ own criterion of ˃160 mils in depth.14 In other words, Phillips
received a report containing information on four anomalies that, under the company’s own
criteria, could potentially present integrity threats to the pipeline, five months before the 180-day
deadline, and yet did nothing.15 As noted above, Respondent later received the vendor’s final
report two days before the 180-day deadline – a report which also noted anomalies on the WT-80
pipeline – but still took no action until after the deadline had passed.16
Phillips’ only defense is that, in this case, the UT crack tool posed particular problems that
prevented the vendor from providing a timely analysis and that Phillips had to upload the data
from the final report into its computer system and review it, a process that stretched beyond the
180-day time frame. 17 However, Phillips failed to provide any evidence demonstrating why it
was impracticable for the vendor to provide the data or for Phillips to derive sufficient
information from the preliminary report submitted by its vendor on November 9, 2009, to make
the requisite determinations within 180 days.
It is well recognized that one of the main purposes of getting a preliminary in-line inspection
(ILI) report within weeks after a “pig” run is to see whether or not there are any anomalies
serious enough to warrant prompt action before receipt of the final report.18 In this case, Phillips
did receive a timely preliminary report that showed four noteworthy anomalies but the company
failed to make any determination under § 195.452(h)(2) within the 180-day period.
PHMSA’s published enforcement guidance reinforces the notion that discovery of a condition
detrimental to the integrity of a pipeline should occur at the earliest opportunity after an ILI
inspection 19 and that discovery can occur at various points in the process, including “when the
vendor notifies the operator of a condition detrimental to the integrity of the pipeline; (2) when
the operator receives a preliminary report from the vendor; (3) when the operator receives the
final report from the vendor; or (4) when the operator performs a validation dig.”20 The
importance of timely discovery is also confirmed by many previous PHMSA enforcement
actions, which have held that discovery must occur within the 180-day deadline unless the
14 Pipeline Safety Violation Report (Violation Report), (May 13, 2014) (on file with PHMSA), at 34.
15 Id. at 271.
16 Response, at 7 – 8.
17 Notice at 5; see also Response at 7 – 9.
18 See 49. C.F.R. § 195.452(h)(4) for the various deadlines to remediate different types of anomalies.
19 PHMSA, Operations and Maintenance Enforcement Guidance, Part 195, Subpart F (Enforcement Guidance) 1, 94
(“Discovery of a condition should occur at the earliest opportunity.”) (citing 67 FR 1653, January 14, 2002),
http://www.phmsa.dot.gov/foia/e-reading-room (site last visited January 26, 2015).
20 Enforcement Guidance at 94.



CPF No. 4-2014-5011
Page 7
operator can prove such time frame to be impracticable.21
In this case, I cannot see that the deadline was impracticable. Accordingly, after considering all
of the evidence, I find Respondent violated 49 C.F.R. § 195.452(h)(2) by failing to obtain
sufficient information within 180 days of an integrity assessment to determine that a condition
presents a potential threat to the integrity of the pipeline.
Item 6: relevant part:
The Notice alleged that Respondent violated 49 C.F.R. § 195.452(b), which states, in
§ 195.452 Pipeline integrity management in high consequence areas.
(a) ….
(b) What program and practices must operators use to manage
pipeline integrity? Each operator of a pipeline covered by this section
must:
(1) Develop a written integrity management program that
addresses the risks on each segment of pipeline in the first column of the
following table not later than the date in the second column: . . .
(5) Implement and follow the program.
The Notice alleged that Respondent violated 49 C.F.R. § 195.452(b) by failing to implement and
follow certain changes in its written Integrity Management Program to ensure that its written
manual and forms were properly maintained and implemented. Specifically, the Notice alleged
that Phillips failed to update and follow Section 5.6.3 of its Integrity Management Manual,
entitled Inspection and Repair, Pipeline Maintenance and Leak Report (Section 5.6.3).
As a result of the alleged failure to update and follow Section 5.6.3, Phillips’ employees
purportedly used outdated forms and procedures when conducting Integrity Management tasks.
Specifically, the Notice asserted that Respondent’s failure to update and follow Section 5.6.3 led
to its employees inaccurately recording data on several occasions, one of which involved
mishandling repairs, and failing to complete several maintenance and construction-related
forms. Lastly, the Notice alleged that Phillips corrected these forms, and the data on the forms,
only after PHMSA brought these inaccuracies to Respondent’s attention.
Respondent did not contest this allegation of violation. Accordingly, based upon a review of all
of the evidence, I find that Respondent violated 49 C.F.R. § 195.452(b) by failing to implement
certain changes that had been made in its Integrity Management Program to ensure that its
written manual and forms were properly maintained and implemented.
21 See, In the Matter of ConocoPhillips, Final Order, C.P.F. No. 4-2005-5037 (January 9, 2007) (where PHMSA
found that Respondent did not provide sufficient proof to rebut the evidence presented by the agency that the
company had sufficient information from the ILI reports to enable discovery of the conditions within the 180-day
deadline). See also, In the Matter of Enbridge Energy, Final Order, C.P.F. No. 3-2012-5013 (September 7, 2012);
and In the Matter of Kinder Morgan Energy Partners, LP, Final Order, C.P.F. No. 2-2011-5002 (June 9, 2011
(available at www.phmsa.dot.gov/pipeline/enforcement).



CPF No. 4-2014-5011
Page 8
Item 7: The Notice alleged that Respondent violated 49 C.F.R. § 195.452(f)(1), which states:
§ 195.452 Pipeline integrity management in high consequence areas.
(a) ….
(f) What are the elements of an integrity management program? An
integrity management program begins with the initial framework. An
operator must continually change the program to reflect operating
experience, conclusions drawn from results of the integrity assessments,
and other maintenance and surveillance date, and evaluation of
consequences of a failure on the high consequence area. An operator must
include, at minimum, each of the following elements in its written
integrity management program:
(1) A process for identifying which pipeline segments could affect a
high consequence area: . . . .
The Notice alleged that Respondent violated § 195.452(f)(1) by failing to identify all pipeline
segments that could affect a high consequence area (HCA).22 Specifically, the Notice alleged
that Phillips had a deficient process for identifying which pipeline segments could affect an
HCA, a process which led it to initially mislabel the point at which pipeline EZ crossed Highway
183 in Austin, Texas, and therefore was not identified as an HCA.
In its Response, Phillips contended it did not violate § 195.452(f)(1) and that its process for
identifying when a pipeline segment could affect an HCA was satisfactory. It presented
evidence that its HCA identification process, addressed in Section 2.4 of its Integrity
Management Plan (IMP 2.4), utilized not only National Pipeline Mapping Service and census
data, but other sources and activities as well. Additionally, Respondent argued that the point at
which pipeline EZ crossed Highway 183 in Austin, Texas, is observed by the company on a
regular basis, that such constant monitoring played a large part in why this point was initially not
classified as an HCA in 2006, and that it was later reclassified as an HCA in 2013 only after new
census data became available.
I agree that Phillips’ process for identifying HCAs was adequate and that its conclusions about
this particular location were reasonable. Therefore, I order that this Item be withdrawn.
22 Section 49 C.F.R. § 195.450 states:
“High consequence area means:
(1) A commercially navigable waterway, which means a waterway where a substantial likelihood of
commercial navigation exists;
(2) A high population area, which means an urbanized area, as defined and delineated by the Census Bureau,
that contains 50,000 or more people and has a population density of at least 1,000 people per square mile;
(3) An other populated area, which means a place, as defined and delineated by the Census Bureau, that
contains a concentrated population, such as an incorporated or unincorporated city, town, village, or other
designated residential or commercial area;
(4) An unusually sensitive area, as defined in § 195.6”.



CPF No. 4-2014-5011
Page 9
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.23 In determining the amount of a civil penalty under 49 U.S.C.
§ 60122 and 49 C.F.R. § 190.225, I must consider the following criteria: the nature,
circumstances, and gravity of the violation, including adverse impact on the environment; the
degree of Respondent’s culpability; the history of Respondent’s prior offenses; 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 $175,300 for the violations cited above.
Item 2: The Notice proposed a civil penalty of $45,700 for Respondent’s violation of
49 C.F.R. § 195.402(a), by failing to follow its own cathodic protection testing procedures.
Respondent did not contest this allegation of violation, but sought a reduction in the proposed
civil penalty. The company contends that the violation was an isolated example and not
“indicative of a systemic problem.”24 In addition, the company indicates that adequate cathodic
protection levels were present and there was no indication of any “elevated concern” regarding
the integrity of the two tanks in question. Finally, the company argues that the penalty amount is
excessive because the violation involved the failure of a Phillips employee to cover one of the
company’s own internal procedures, not an express pipeline regulation.25
I have reviewed the evidence supporting the penalty considerations and find the proposed
penalty to be reasonable and the penalty assessment factors properly applied. As for the nature of
the violation, PHMSA took into account that the violation involved the failure to follow the
company’s own procedures and not simply a records violation and adjusted the penalty
accordingly. As for gravity, PHMSA recognized that the tanks had adequate corrosion
protection readings and that the violation had only a minimal impact on safety; on the other
hand, there were multiple instances of violation and not just a single occurrence. Even though
there was a minimal impact on safety, the failure of Phillips to conduct proper inspections could
have easily jeopardized safety and resulted in a release and significant damage to life, property,
or the environment.26
Accordingly, having reviewed the record and considered the assessment criteria, I assess
Respondent a civil penalty of $45,700 for violating of 49 C.F.R. § 195.402(a).
23 Effective January 3, 2012, the maximum administrative civil penalties for violations of the federal pipeline safety
regulations were doubled to $200,000 per violation per day of violation with a maximum of $2,000,000 for a related
series of violations (The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (Pub. L. 112-90)).
Because the violations in this case occurred prior to the increase, the higher maximums do not apply.
24 Response, at 2 – 3.
25 Id.
26 Violation Report, at 11 – 17.



CPF No. 4-2014-5011
Page 10
Item 3: The Notice proposed a civil penalty of $86,400 for Respondent’s violation of
49 C.F.R. §§ 195.505(a–b), for failing to ensure through evaluation that employees were
qualified to perform covered tasks on 29 separate occasions.
Respondent did not contest the violation, but requested a reduction in the proposed civil penalty,
based largely on the various measures the company has taken subsequent to the inspection to
ensure compliance. Phillips contends it has spent more than the proposed civil penalty of
$86,400 by taking steps to limit supervisor turnover, as well as to ensure better monitoring of
employee qualifications.
I have reviewed the evidence in the record and find that the penalty for this Item was fairly and
properly calculated. While Phillips is to be commended for the post-inspection actions it has
taken to improve compliance, such actions are ones that any prudent operator would take in
response to a violation. It is critical that an operator ensure all of its employees are properly
qualified to perform safety-related tasks; the safety of the facility, as well as the environment
surrounding it, depend upon it.
Accordingly, having reviewed the record and considered the assessment criteria, I assess
Respondent a civil penalty of $86,400 for violating of 49 C.F.R. §§ 195.505(a–b).
Item 5: The Notice proposed a civil penalty of $43,200 for Respondent’s violation of 49 C.F.R.
§ 195.452(h)(2) for failing to obtain sufficient information within 180 days of an integrity
assessment to enable the company to determine that a condition presents a potential threat to the
integrity of the pipeline. As discussed above, I found that it was not impracticable for Phillips to
have obtained sufficient information within such time period to make a determination about
conditions that potentially threatened the integrity of the pipeline.
Respondent objected to the amount of the proposed penalty and requested its reduction or
elimination. Phillips asserts that the penalty is excessive because a review of company records
dating back to 2009 reveals this to be the only instance where it exceeded the 180-day deadline.
Phillips also contends that it has taken steps since the inspection to ensure future compliance
with § 195.452(h)(2).
I have reviewed the evidence in the record and find the assessment factors relating to “nature,
circumstances and gravity” were reasonably applied in this case. As noted earlier, Phillips is to
be commended for taking post-inspection actions to improve compliance, but such actions are
ones that any prudent operator would take in response to a violation. The company also notes
that this was the only violation of the 180-day deadline committed by Phillips since 2009. While
this may be true, the gravity of this violation is increased because it could affect an HCA and
was discovered not by the operator but by PHMSA. It is fortunate that the company’s failure to
discover several anomalies requiring prompt repair did not, in this instance, compromise safety
or lead to a release that could have caused significant environmental damage. It is critical that
pipeline integrity assessments be completed and acted upon at the earliest possible opportunity,
not months later.



CPF No. 4-2014-5011
Page 11
Accordingly, having reviewed the record and considered the assessment criteria, I assess
Respondent a civil penalty of $43,200 for violating of 49 C.F.R. § 195.452(h)(2).
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 $175,300.
COMPLIANCE ORDER
The Notice proposed a compliance order with respect to Items 4, 5, 6, and 7 in the Notice for
violations of 49 C.F.R. §§ 195.432(b), 195.452(h)(2), 195.452(b)(5), and 195.452(f)(1),
respectively. Item Seven has been withdrawn, and therefore Phillips is not ordered to take steps
to ensure compliance with § 195.452(f)(1).
Under 49 U.S.C. § 60118(a), each person who engages in the transportation of gas or who owns
or operates a 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:
1. With respect to the violation of § 195.432(b) (Item 4), Respondent must develop
procedures that clearly identify when a corrosion rate of zero can be assumed.
Phillips must also develop a procedure that clearly identifies if historic corrosion has
occurred, and establish an appropriate corrosion rate from the measured data in
accordance with API 653. After developing procedures, Phillips must re-evaluate its
tank-inspection intervals against the revised procedure to ensure that the internal
inspection intervals are calculated in accordance with API 653. Lastly, Phillips must
ensure that inspections occur prior to reaching the minimum plate thickness necessary
to ensure tank plate integrity.
2. With respect to the violation of § 195.452(h)(2) (Item 5), Respondent must amend
its IEP 1.03 – Reporting Requirements for Pipeline In – Line Inspection Procedure to
be consistent with the regulatory requirement of § 195.452(h)(2).
3. With respect to the violation of § 195.452(b)(5) (Item 6), Respondent must amend
Section 5.6.3 of its Integrity Management Plan and remove references to deleted
procedures.
4. Respondent must provide PHMSA with documentation that verifies completion of
numbers 1 and 2 above within 45 days following the receipt of the Final Order.
5. It is requested (not mandated) that Phillips Pipeline LLC maintain documentation
of the safety improvement costs associated with fulfilling this Compliance Order and
submit the total to R.M. Seeley, Director, Southwest Region, Pipeline and Hazardous
Materials Safety Administration. It is requested that these costs be reported in two
categories: 1) total cost associated with preparation/revision of plans, procedures,



CPF No. 4-2014-5011
Page 12
studies and analyses; and 2) total cost associated with replacements, additions, and
other changes to pipeline infrastructure.
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 and demonstrating good cause for an
extension.
Failure to comply with this Order may result in the administrative assessment of civil penalties
not to exceed $200,000 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 ITEMS
With respect to Items 1, 8, and 9, the Notice alleged probable violations of Part 195 but did not
propose a civil penalty or compliance order for these items. Therefore, these are considered to
be warning items. The warnings were for:
49 C.F.R. § 195.402(a) (Item 1) ─ Respondent’s alleged failure to follow its
atmospheric storage tank level alarm procedure, as set forth in its written
operations manual;
49 C.F.R. § 195.402(a) (Item 8) ─ Respondent’s alleged failure to follow its
welding procedures and welder qualification requirements, as set forth in its
written operations manual; and
49 C.F.R. § 195.452(b) (Item 9) ─ Respondent’s alleged failure to follow its
procedures for the evaluation or repair of external or internal pipeline defects and
anomalies, as set forth in its written integrity management program.
Respondent presented information in its Response showing that it had taken certain actions to
address the cited items. If OPS finds a violation of any of these provisions in a subsequent
inspection, Phillips may be subject to future enforcement action.
Under 49 C.F.R. § 190.243, Respondent has a right to submit a Petition for Reconsideration of
this Final Order. The petition must be sent to: Associate Administrator, Office of Pipeline
Safety, PHMSA, 1200 New Jersey Avenue, SE, East Building, 2nd Floor, Washington, District of
Columbia, 20590, with a copy sent to the Office of Chief Counsel, PHMSA, at the same address.
PHMSA will accept petitions received no later than 20 days after receipt of service of this Final
Order by the Respondent, provided they contain a brief statement of the issue(s) and meet all
other requirements of 49 C.F.R. § 190.215. The filing of a petition automatically stays the
payment of any civil penalty assessed.



CPF No. 4-2014-5011
Page 13
Unless the Associate Administrator, upon request, grants a stay, all other 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

420145011_Closure Letter_05102018_text.pdf

CERTIFIED MAIL - RETURN RECEIPT REQUESTED
May 14, 2018
Mr. Todd Denton
President
Phillips 66 Pipeline LLC
1075 W Sam Houston Pkwy
N. Suite 200 N812-03
Houston, TX 77043
CPF 4-2014-5011
Dear Mr. Denton:
On September 11, 2015, the Pipeline and Hazardous Materials Safety Administration (PHMSA)
issued to Phillips 66 Pipeline LLC 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,
Mary L. McDaniel, P.E.
Director, Southwest Region
Office of Pipeline Safety
Pipeline and Hazardous Materials Safety Administration

## Provenance

- Official: Yes
- Source: <https://primis.phmsa.dot.gov/enforcement-data/case/420145011>
- Source ID: `phmsa-enforcement`
- SHA-256: `880b66b2579f5ee14ec0431f34bcd52f9b3f16c48198051048fb3a23cc8dea31`
- Retrieved: 2026-08-20T04:44:44.458Z
- Exported: 2026-08-24T09:34:54.730Z
- Document slug: `phmsa-enforcement-420145011`

### Source metadata

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  "pipelineType": "INTERSTATE LIQUID ONSHORE",
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  "jurisdiction": "US",
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}
```