# EXXONMOBIL PIPELINE CO — Notice of Probable Violation

- **operation:** document
- **citation:** CPF 420115016
- **title:** EXXONMOBIL PIPELINE CO — Notice of Probable Violation
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2011-11-07
- **effective on:** Not available
- **summary:** CLOSED notice of probable violation citing 195.302, 195.452(h)(2), 195.452(h)(4).
- **machine formats:** - **json:** https://regulus.evalyn.ai/document/phmsa-enforcement-420115016.json
- **markdown:** https://regulus.evalyn.ai/document/phmsa-enforcement-420115016.md
- **app url:** https://regulus.evalyn.ai/document/phmsa-enforcement-420115016
- **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/420115016
**body:**

Notice of Probable Violation involving EXXONMOBIL PIPELINE CO. PHMSA's enforcement data identifies the cited regulations as 195.302,  195.452(h)(2),  195.452(h)(4). The case was opened on 2011-11-07 and is reported as closed as of 2019-08-26. Proposed civil penalty: $151,100. Assessed civil penalty: $101,500. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

420115016_Closure Letter_08262019.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420115016/420115016_Closure%20Letter_08262019.pdf

420115016_Closure Letter_08262019_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420115016/420115016_Closure%20Letter_08262019_text.pdf

420115016_Decision on Petition_07092014.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420115016/420115016_Decision%20on%20Petition_07092014.pdf

420115016_Decision on Petition_07092014_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420115016/420115016_Decision%20on%20Petition_07092014_text.pdf

420115016_Final Order_06272013.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420115016/420115016_Final%20Order_06272013.pdf

420115016_Final Order_06272013_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420115016/420115016_Final%20Order_06272013_text.pdf

420115016_NOPV PCP PCO_11072011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420115016/420115016_NOPV%20PCP%20PCO_11072011.pdf

420115016_NOPV PCP PCO_11072011_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420115016/420115016_NOPV%20PCP%20PCO_11072011_text.pdf

420115016_Operator Response to NOPV PCP PCO_12152011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420115016/420115016_Operator%20Response%20to%20NOPV%20PCP%20PCO_12152011.pdf

420115016_Petition_for_Reconsideration_07222013.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420115016/420115016_Petition_for_Reconsideration_07222013.pdf

420115016_Final Order_06272013_text.pdf

JUNE 27, 2013
Mr. Gary Pruessing
President
ExxonMobil Pipeline Company
800 Bell St., Room 741-D
Houston, TX 77002
Re: CPF No. 4-2011-5016
Dear Mr. Pruessing:
Enclosed please find the Final Order issued in the above-referenced case. It makes findings of
violation, assesses a reduced civil penalty of $112,300, withdraws several alleged violations, and
specifies actions that need to be taken by ExxonMobil Pipeline Company 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 is made pursuant to 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. R.M. Seeley, Director, Southwest Region, OPS
Mr. Alan Mayberry, Deputy Associate Administrator for Field Operations, OPS
Ms. Catherine Little, Hunton & Williams LLP, Bank of America Plaza, Suite 4100
600 Peachtree Street, N.E., Atlanta, GA 30308
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 )
ExxonMobil Pipeline Company, ) CPF No. 4-2011-5016
)
)
)
Respondent. )
___________________________________ )
FINAL ORDER
On March 31-April 1, 2011, pursuant to 49 U.S.C. § 60117, representatives of the Pipeline and
Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS),
conducted an on-site pipeline safety inspection of the records and procedures of ExxonMobil
Pipeline Company (EMPCo or Respondent) in Houston, Texas. EMPCo, a subsidiary of Exxon
Mobil Corporation, operates approximately 4,000 miles of pipeline transporting crude oil,
refined petroleum products, and highly volatile liquids in Texas, Louisiana, and Montana.1
As a result of the inspection, the Director, Southwest Region, OPS (Director), issued a Notice of
Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (Notice) to
Respondent on November 7, 2011. In accordance with 49 C.F.R. § 190.207, the Notice alleged
that Respondent committed violations of the pipeline safety regulations in 49 C.F.R. Part 195
and proposed a total civil penalty of $151,100 for the alleged violations. The Notice also
proposed corrective action to be completed.
EMPCo responded to the Notice by letter dated December 15, 2011 (Response). In its Response,
Respondent contested the alleged violations and requested a hearing. Respondent provided
additional written explanations by letter dated April 16, 2012. A hearing was held in accordance
with 49 C.F.R. § 190.211 on April 25, 2012, in Houston, Texas, before the Presiding Official
from the Office of Chief Counsel, PHMSA. After the hearing, Respondent submitted additional
written material by letters dated June 29 and August 30, 2012.
FINDINGS OF VIOLATION
The Notice alleged that Respondent violated 49 C.F.R. Part 195, as follows:
1 Pipeline system information for calendar year 2011 was reported by EMPCo pursuant to 49 C.F.R. § 195.49.



2
Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 195.302, which states, in
relevant part:
§ 195.302 General requirements.
(a) [N]o operator may operate a pipeline unless it has been pressure
tested under this subpart without leakage . . . .
(c) Except for pipelines . . . covered under § 195.303, the following
compliance deadlines apply to pipelines . . . that have not been pressure
tested under this subpart . . .
(2) For pipelines scheduled for testing, each operator shall—
(i) Before December 7, 2000, pressure test—
(A) Each pipeline identified by name, symbol, or otherwise that
existing records show contains more than 50 percent by mileage (length)
of electric resistance welded pipe manufactured before 1970; and
(B) At least 50 percent of the mileage (length) of all other pipelines;
and
(ii) Before December 7, 2003, pressure test the remainder of the
pipeline mileage (length).
The Notice alleged that Respondent violated § 195.302 by operating 27 pipeline segments that
had not been pressure tested by the deadlines set forth in the regulation. OPS included in the
record evidence of a spreadsheet prepared by Respondent titled, “Systems Lacking DOT
Hydrotest Documentation” (Spreadsheet), which listed 27 pipeline segments totaling 615.7
miles.
2
In its written submissions prior to the hearing, Respondent explained that the Spreadsheet had
been prepared in 1998 as part of its effort to comply with the deadline in 49 C.F.R. § 195.302.
Respondent produced information regarding the current status of the 27 pipeline segments.
Respondent contended that: (a) twelve were pressure tested; (b) five were purged of product and
idled; (c) two were sold; (d) five were exempt from § 195.302 because they were covered under
§ 195.303; and (e) three were exempt from Part 195 altogether.
3 At the hearing, Respondent
discussed in more detail the eight segments that it claimed were exempt. Respondent provided a
post hearing submission with additional records regarding all 27 segments.
Applicable safety standards
Beginning in 1971, each newly constructed pipeline transporting hazardous liquids was required
to undergo a pressure test in accordance with 49 C.F.R. Part 195, Subpart E. In 1994, the
pressure testing requirements were extended to all hazardous liquid pipelines, including those
constructed before 1971. Deadlines for testing older pipelines were established in
§ 195.302(c)(2). In 1998, § 195.303 was adopted to allow operators of older pipelines to elect an
alternative testing and inspection program to evaluate the integrity of the lines based on
individual risk factors.
2 OPS Pipeline Safety Violation Report, Exhibit 1-2 (Nov. 7, 2011) (Violation Report).
3 EMPCo letter dated April 16, 2012, p.2 (Pre-hearing Submittal).



3
Certain record keeping requirements were established to ensure that any pressure test or
alternative program complied with the applicable requirements. Operators were required to
make and retain for each pressure test documentation including, among other things: pressure
recording charts; test instrument calibration data; date and time of the test; minimum test
pressure; a description of the facility tested; and temperature of the test medium or pipe during
the test period.4 If an operator elected to follow a risk-based alternative to pressure testing,
§ 195.303 required the operator to maintain records verifying the risk classifications, the plans
and schedule for testing, the conduct of the testing, and ongoing review of risk classifications.
Findings
The following findings are made with regard to each of the 27 pipeline segments at issue. The
segments are categorized by their alleged disposition according to Respondent. Next to each
segment name is a number that corresponds to the order in which the segment was listed on the
1998 Spreadsheet.
a. Segments that Respondent Claimed Were Pressure Tested
PCU to Mt. Belvieu Poly Propylene (Segment 2)
Respondent contended that the PCU to Mt. Belvieu Poly Propylene pipeline segment was
pressure tested in 1981, 2004, and 2009, and therefore the segment was in compliance with
§ 195.302 at the time of the OPS inspection.
Respondent submitted a diagram of the Baytown PCU Polymer Grade Propylene System and
records from pressure tests that took place in 1980 on the system.
5 Hand-drawn diagrams
attached to the test records depicted about 750 feet of tested pipe. Respondent did not submit
any test records from 2004 or 2009.
The 1998 Spreadsheet indicated the PCU to Mt. Belvieu Poly Propylene segment that did not
have adequate pressure test documentation was 0.27 miles or approximately 1,427 feet in length.
The evidence fails to demonstrate the entire 0.27-mile segment was pressure tested according to
§ 195.302. For this reason, I find the segment was not in compliance.
St. James to Junction (Segment 4)
Respondent contended that the St. James to Junction pipeline segment was pressure tested in
1968 and therefore the segment was in compliance with § 195.302 at the time of the OPS
inspection. To support this contention, Respondent submitted a single page Pipeline
Qualification Record dated 1968.6
4 § 195.310.
5 EMPCo letter dated June 29, 2012, Exhibits 9 and 10 (Post-hearing Submission).
6 Post-hearing Submission, Exhibit 18.



4
The record submitted by Respondent is not sufficient to demonstrate a pressure test was
conducted in accordance with Subpart E because the record lacked necessary information such as
a pressure recording chart. Without adequate documentation of a pressure test, I find this
segment was not in compliance.
Webster to Baytown #3 and #6-8 inch (Segment 11)
Respondent contended that the Webster to Baytown #3 and #6-8 inch pipeline segment was
pressure tested in 2000 and therefore was in compliance with § 195.302 at the time of the OPS
inspection. Respondent also noted that this segment was idled after the OPS inspection.
Respondent submitted records from a pressure test that occurred in 2000.7 These records are not
sufficient to demonstrate a pressure test was conducted in accordance with Subpart E because the
records did not include any pressure recording charts. In addition, the records did not reference
the entire 1.08-mile Webster to Baytown #3 and #6-8 inch pipeline segment listed in the
Spreadsheet. For these reasons, I find the segment was not in compliance.
BOP to ITC Butadiene (Segment 12)
Respondent contended that due to a naming discrepancy, this pipeline segment was either the
BOP to ITC Crude Butadiene system, which was pressure tested in 1979 and 2003, or it was the
BOP to ITC Product Butadiene system, which was pressure tested in 1981. Since both were
pressure tested, Respondent contended the segment was in compliance with § 195.302 at the time
of the OPS inspection.
Respondent submitted records from a pressure test that took place in 1979 on the “Chocolate
Bayou—BOP Cr[ude] Butadiene Sys[tem] (ITC Lateral).”8 Respondent also submitted records
from a test that took place in 1980 on what appears to be a different pipeline, but not the product
line referenced above. The segment tested in 1980 was the “Chocolate Bayou to Baytown Crude
Butadiene.”9 Respondent did not submit any test records that could be identified for the BOP to
ITC Product Butadiene system or any records from a pressure test in 2003.
The records submitted by Respondent are not sufficient to demonstrate that the pipeline segment
referenced on the Spreadsheet was pressure tested in accordance with § 195.302 because the
records submitted did not include any pressure recording charts. Accordingly, I find this
segment was not in compliance.
7 Post-hearing Submission, Exhibit 46.
8 Post-hearing Submission, Exhibit 53. Respondent submitted these records in duplicate for the Chocolate Bayou -
BOP Crude Butadiene (Segment 24, see below), but did not explain why identical records were submitted for
different pipeline segments.
9 Post-hearing Submission, Exhibit 54.



5
Boyce to Bunkie (Segment 14)
Respondent contended that the Boyce to Bunkie pipeline segment was pressure tested in 2000 or
2001 and therefore was in compliance with § 195.302 at the time of the OPS inspection.
Respondent also noted that the segment was renamed Melville to Boyce after a reversal in 2001.
Respondent submitted records from two pressure tests that took place in 2001—one from Boyce
to Chandler, which covered approximately 21 miles, and one from Chandler to Bunkie, which
covered slightly less than 21 miles, for a total of about 42 miles.10
The evidence submitted by Respondent does not demonstrate the entire 46.3-mile segment listed
in the Spreadsheet was pressure tested in accordance with Subpart E. Furthermore, the records
were insufficient because they did not include any pressure recording charts. Accordingly, I find
this segment was not in compliance.
Bunkie to Anchorage (Segment 15)
Respondent contended that the Bunkie to Anchorage pipeline segment was pressure tested in
2000 or 2001 and therefore the segment was in compliance at the time of the OPS inspection.
Respondent noted this segment was renamed Anchorage to Melville and Melville to Boyce after
a 2001 reversal.
Respondent submitted records from two pressure tests that took place in 2001—one from Bunkie
to Hwy 361, which covered approximately 12.31 miles, and one from Hwy 361 to AR Melville
West, which covered approximately 19.48 miles, for a total of about 32 miles.11
The evidence submitted by Respondent does not demonstrate the entire 51.41-mile segment
listed in the Spreadsheet was pressure tested. Furthermore, the records were insufficient because
they did not include any pressure recording charts. Accordingly, I find this segment was not in
compliance.
Finney to Boyce (Segment 16)
Respondent contended that the Finney to Boyce pipeline segment was pressure tested in 2000 or
2001 and therefore the segment was in compliance at the time of the OPS inspection.
Respondent also noted the segment was renamed Boyce to Finney after the 2001 reversal.
Respondent submitted records of pressure tests that took place in 2001.12 The records were
insufficient because they did not include any pressure recording charts. Accordingly, I find this
segment was not in compliance.
10 Post-hearing Submission, Exhibits 58 and 59.
11 Post-hearing Submission, Exhibits 62 and 63. Another record, Exhibit 64, appeared to concern a test on a
different pipeline segment.
12 Post-hearing Submission, Exhibit 68.



6
Strang Road to Texas City (Segment 21)
Respondent contended that the Strang Road to Texas City pipeline segment was pressure tested
in 1997 and therefore the segment was in compliance at the time of the OPS inspection.
Respondent also noted that this segment is now part of the Fairmont Junction to Texas City
Propylene System.
Respondent submitted records from a pressure test that took place in 1997 at “various locations”
on the “Bayport Jct. to Texas City section.”13 An attachment to the test record indicated the test
began at station 444+27 (valve 3506) and ended at station 1058+33 (valve 3524).14 Respondent
also submitted several pipeline diagrams.
15 The station and valve identification numbers from
the test record did not appear to correlate to any one diagram in a manner that clearly
demonstrated the 2.86-mile Strang Road to Texas City segment referenced in the Spreadsheet
had been pressure tested. In addition, the pressure test records were insufficient because they did
not include any pressure recording charts. Accordingly, I find this segment was not in
compliance.
Texas Olefins Multi-Products Crossover (Segment 22)
Respondent contended that the Texas Olefins Multi-Products Crossover pipeline segment was
pressure tested in 1982 and therefore the segment was in compliance at the time of the OPS
inspection.
Respondent submitted records from a pressure test that took place in 1982 on the “BOP - Texas
Olefins Spare Liquid Hydrocarbon Line.”16 Respondent submitted a duplicate of this record for
the BOP to Texas Olefins Raffinate segment (Segment 23, see below).
The station identification numbers from the 1982 test record did not appear to correlate to the
diagram Respondent submitted for this segment. In addition, the records were insufficient
because they did not include any pressure recording charts. Accordingly, I find this segment was
not in compliance.
Chocolate Bayou BOP Crude Butadiene (Segment 24)
Respondent noted that due to a naming discrepancy, this pipeline segment is now part of the
Chocolate Bayou - BPU Butylene System. Respondent contended that it was pressure tested in
1981 and therefore was in compliance at the time of the OPS inspection.
Respondent submitted records from a pressure test that took place in 1979 on the “Chocolate
Bayou-BOP Cr. Butadiene Sys (ITC Lateral).” This same record was submitted by Respondent
13 Post-hearing Submission, Exhibit 85.
14 Post-hearing Submission, Exhibit 86.
15 Post-hearing Submission, Exhibit 84.
16 Post-hearing Submission, Exhibit 90.



7
for the BOP to ITC Butadiene segment (Segment 12, see above). Several of the diagrams
submitted for this segment were also duplicates.
As I have already determined for these records in regard to the BOP to ITC Butadiene segment,
the records were insufficient to demonstrate a pressure test had been conducted in accordance
with Subpart E because they did not include any pressure recording charts. For these reasons, I
find this segment was not in compliance.
Clovelly to Raceland 16-inch Import (Segment 25)
Respondent contended that this pipeline segment was pressure tested in 1966 and therefore the
segment was in compliance at the time of the OPS inspection.
Respondent submitted records from a pressure test that took place in 1966, which were attached
to a report prepared in 1996. According to the report, the test “was performed on the 6.21 mile,
#2-16[inch] pipeline segment from Clovelly Junction to LaRose Junction (Import System).”17
The evidence submitted by Respondent does not demonstrate the entire 16.79-mile segment
listed in the Spreadsheet was pressure tested. For this reason, I find the segment was not in
compliance.
Viola to Hess Refinery #2 - 6 inch Line (Segment 27)
Respondent contended that this pipeline segment was pressure tested in 1999 and 2011 and
therefore it was in compliance at the time of the OPS inspection.
Respondent submitted records from pressure tests that took place in 1999 on the “Corpus Christi
to King Ranch Gas Plant Propane System-Coastal States to Viola 6[-inch]” and the “King Ranch
to Coastal States Propane System Viola to Coastal States 6[-inch].”18 The records submitted
were insufficient to demonstrate the pressure tests were conducted in accordance with Subpart E
because they did not include any pressure recording charts. Respondent did not submit any
records from a pressure test performed on this segment in 2011. Accordingly, I find this segment
was not in compliance.
b. Segments that Respondent Claimed Were Idled Prior to the Inspection19
Avery Island to Lydia (Segment 6)
Respondent contended that the Avery Island to Lydia pipeline segment was idled in 2011, prior
to the OPS inspection, and has since been abandoned. Respondent further contended that the
17 Post-hearing Submission, Exhibit 99.
18 Post-hearing Submission, Exhibit 104.
19 Respondent contended in its Pre-hearing Submittal that five segments were in compliance because they had been
purged of product and idled; however, the evidence produced suggested Respondent intended to make this claim for
four segments.



8
segment was pressure tested in 2000 and 2005.
The pipeline safety regulations do not explicitly recognize a pipeline as “idled,” although the
term is commonly used to refer to pipelines in which operations have been temporarily
suspended.20 Respondent stated that it uses the term to mean “deactivated and filled with
nitrogen.”21 The status of any one of the 27 pipeline segments as inactive or idled at the time of
the OPS inspection does not by itself excuse noncompliance if Respondent had operated the
pipeline without a pressure test in violation of § 195.302.
Respondent submitted a report from a pressure test that took place in 2000 on the Avery Island
pipeline.22 The test covered 49,210 feet of 6-inch pipe. Respondent also submitted some forms
from a pressure test that was performed in 2005, although those records were incomplete.
The Avery Island to Lydia segment listed on the Spreadsheet was 8.16 miles, or approximately
43,085 feet in length. That is approximately 6,000 feet less than the amount that was tested in
2000. The reason for the discrepancy in mileage was not apparent, but the additional mileage
tested could have been part of the system depicted in a diagram Respondent produced showing
9.06 miles (47,837 feet) of 6-inch pipe, plus an additional 1.7 miles (8,976 feet) of mixed 6- and
4-inch pipe.23 Based on this evidence, I find the segment was pressure tested and Respondent
has maintained the necessary documentation. Accordingly, this alleged violation is withdrawn.
Weeks Island to Olivier (Segment 10)
Respondent contended that the Weeks Island to Olivier pipeline segment was idled in 2010 and
remains idled at this time. Respondent further contended that the segment was pressure tested in
2000 and 2005. Respondent submitted pressure test records from 2000 and 2005.24
The records submitted by Respondent were not sufficient to demonstrate the pipeline segment
had been pressure tested in accordance with Subpart E because no pressure recording charts were
included. Without adequate pressure test documentation, I find the pipeline was operated out of
compliance with § 195.302. The status of the segment as idled at the time of the OPS inspection
does not excuse noncompliance.
BOP to Petrotex Mixed Butylene (Segment 19)
Respondent contended that the BOP to Petrotex Mixed Butylene pipeline segment was idled at
some point prior to the OPS inspection and remains idled at this time. Respondent further
20 Abandoned pipelines, by comparison, are recognized in the regulations as ones that have been permanently
removed from service by safely disconnecting the line from the operating pipeline system, purging of combustibles,
and sealing to minimize safety and environmental hazards if left in place.
21 Post-hearing Submission, Exhibit 6, p 2.
22 Post-hearing Submission, Exhibit 28.
23 Post-hearing Submission, Exhibit 27.
24 Post-hearing Submission, Exhibit 46.



9
contended that the segment was pressure tested in 1982. Respondent noted that the segment has
been renamed BOP to TOP Junction.
The records submitted by Respondent were from a pressure test in 1982 and appear to contain all
of the information required by § 195.310, including pressure recording charts and test instrument
calibration data. Based on this evidence, I find Respondent has demonstrated the segment was
pressure tested. This alleged violation is withdrawn.
BOP to Texas Olefins Raffinate (Segment 23)
Respondent contended that the BOP to Texas Olefins Raffinate pipeline segment was idled in
2003 and remains idled at this time. Respondent further contended that the segment was
pressure tested in 1982.
Respondent submitted test records from 1982 for the “BOP - Texas Olefins Spare Liquid
Hydrocarbon Line.”25 Some of the same records were also provided for the Texas Olefins Multi-
Products Crossover (Segment 22, see above).26
The test record station identification numbers appear to correlate with the diagram of this
pipeline segment and appear to contain all of the information required by § 195.310, including
pressure recording charts and test instrument calibration data. Based on the evidence, I find
Respondent has demonstrated the pipeline segment was pressure tested. This alleged violation is
withdrawn.
c. Segments that Respondent Claimed Were Sold
Means to Ector (Segment 1)
Respondent contended that the Means to Ector pipeline segment was sold in 2004. Respondent
also stated that prior to the sale, the segment did not have to comply with the pressure testing
requirement in § 195.302 because the segment had been “derated,” meaning the maximum
operating pressure (MOP) was established under § 195.406(a)(5) based on 80 percent of the
highest operating pressure to which the pipeline was subjected (see § 195.302(b)(1)).
Respondent submitted a Bill of Sale showing this segment was sold in 2004.27 Based on this
evidence, I find Respondent did not operate this pipeline during the time period relevant to this
case, which is five years prior to issuance of the Notice. This alleged violation is withdrawn.
Bullard to Gate Plant “C” (Segment 13)
Respondent contended that the Bullard to Gate Plant “C” pipeline segment was sold in 2000.
Respondent also stated that prior to the sale the segment did not have to comply with the
25 Post-hearing Submission, Exhibit 93.
26 Post-hearing Submission, Exhibit 90.
27 Post-hearing Submission, Exhibit 8.



10
pressure testing requirement in § 195.302 because Respondent had elected the risk-based
alternative to pressure testing under § 195.303 (see § 195.302(b)(4)).
Respondent submitted a Purchase and Sale Agreement showing the segment was sold in 2000.28
Based on this evidence, I find Respondent did not operate this pipeline during the time period
relevant to this case. This alleged violation is withdrawn.
d. Segments that Respondent Claimed Were Exempt from § 195.302 Under a Risk-Based
Alternative Program29
Pierce Junction to Luling (Segment 3)
Respondent contended that the Pierce Junction to Luling pipeline segment did not have to
comply with the pressure testing requirement in § 195.302 because Respondent had elected a
risk-based alternative to pressure testing covered under § 195.303 (see § 195.302(b)(4)). In
addition, Respondent contended that the segment was pressure tested in 1961, 1969, and 1992.
As noted above, § 195.303 permitted operators to elect a risk-based program for older pipelines
as an alternative to the pressure test deadlines set forth in § 195.302(c)(2). An operator electing
this approach in 1998 was required to evaluate each pipeline segment according to a list of risk
factors and to assign each pipeline segment a corresponding risk classification.30 Pressure tests
were still required for pipelines constructed of electric resistance-welded (ERW) pipe
manufactured prior to 1970 that were susceptible to longitudinal seam failures. Other segments,
depending on risk classification, could be evaluated with an inline inspection (ILI). Pipelines in
the lowest risk category were not subject to additional measures. Deadlines for testing and
inspections under the alternative program were specified in § 195.303(f).
In accordance with § 195.303(d), all pre-1970 ERW pipe was deemed susceptible to longitudinal
seam failures unless an engineering analysis showed otherwise. In conducting an engineering
analysis, an operator was required to consider among other things: (1) seam-related leak history
of the pipe and pipe manufacturing information as available, including the pipe steel’s
mechanical properties and fracture toughness; (2) the manufacturing process and controls related
to seam properties, including whether the ERW process was high-frequency or low-frequency,
whether the weld seam was heat treated, whether the seam was inspected, the test pressure and
duration during mill hydrotest; (3) the quality control of the steel-making process; and (4) other
factors pertinent to seam properties and quality.
28 Post-hearing Submission, Exhibit 56.
29 Respondent contended in its Pre-hearing Submittal that five segments were exempt from § 195.302 because they
were covered by § 195.303; however, the evidence produced suggested Respondent intended to make this claim for
six segments.
30 An operator electing to follow an alternative program was required to develop the plans and schedule for testing
by December 7, 1998.



11
According to Respondent’s record, the Pierce Junction to Luling pipeline segment was
“[c]omposed almost exclusively of pre-1970 ERW pipe.”31 This means it was required to be
deemed susceptible to longitudinal seam failures and pressure tested, unless an engineering
analysis showed otherwise. Respondent produced an engineering analysis for the segment
completed in 1999. The analysis concluded that the segment was not susceptible to seam failures
based on an evaluation of leak history, design pressure, and pipe metallurgy. With regard to leak
history, the analysis concluded there was no propensity to seam-related failures because only two
failures were documented during pressure tests. In one failure, it was noted that “the weld seam
provided a weak path along which to grow,” but the root cause of the crack was determined to be
a gouge. Design pressure and pipe metallurgy were found to be within specification. The
analysis did not contain any information about the manufacturing process and controls.
Having reviewed the engineering analysis for the Pierce Junction to Luling segment, I find it did
not give adequate consideration to the weakness along the longitudinal seam discovered at one of
the failure sites. The weakness of the seam was a significant finding during the evaluation of
seam integrity. Even though seam failure was not the root cause of the leak, there was an
absence of analysis supporting a conclusion that there was no propensity for seam-related failure
despite the weakness of the seam. In addition, there was no information regarding the
manufacturing process and controls of the pipe. In accordance with the regulatory presumption
that all pre-1970 ERW pipelines are susceptible to seam failure unless otherwise shown, these
factors should have weighed in favor of a conservative conclusion regarding susceptibility. I
find the engineering analysis did not have sufficient support for concluding the pre-1970 ERW
segment was not susceptible to longitudinal seam failure.
Under § 195.303, all pre-1970 ERW pipeline segments susceptible to seam failure covered by a
risk-based alternative program were required to be pressure tested unless the analysis showed
otherwise, which in this case it did not. Respondent contended that even though it believed a
pressure test was not required, the Pierce Junction to Luling segment was pressure tested in
1961, 1969, and 1992. Respondent submitted certain pressure test records from 1961 and
1992.32
The records submitted by Respondent were not sufficient to demonstrate the entire pipeline
segment had been pressure tested. The records from 1961 did not include pressure recording
charts and the records from 1992 did not document a pressure test on the entire 140.9-mile
segment. Without adequate pressure test documentation or an acceptable analysis showing a
pressure test was not required, I find the pipeline was operated out of compliance.
SMI 6A to South Bend (Segment 5)
Respondent contended that this pipeline segment did not have to comply with the pressure
testing requirement in § 195.302 because Respondent had elected the risk-based alternative to
31 Post-hearing Submission, Exhibit 12.
32 Post-hearing Submission, Exhibits 14-16.



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pressure testing covered under § 195.303. Respondent did not contend the SMI 6A to South
Bend segment was ever pressure tested.33
The SMI 6A to South Bend pipeline segment was “[c]omposed almost exclusively of pre-1970
ERW pipe.”34 Respondent produced an engineering analysis completed in 1998, which
concluded that the pre-1970 ERW pipe was not susceptible to seam failures. This conclusion
was based on an evaluation of leak history, design pressure, pipe manufacturing, and pipe
metallurgy. With regard to leak history, the analysis noted two leaks on the body of the pipe
caused by outside force damage and no history of seam-related leaks. The vintage,
manufacturer, and pipe mill were all considered. No manufacturing records were located from
the mill, but the pipe specification license of the mill was considered. The license would have
required the mill to perform pressure tests and nondestructive inspection of all ERW welded
seams along with visual inspections.
Analysis of the metallurgy noted that the pipe was manufactured using high-frequency ERW
welding, but the analysis found there had been no normalization by post-weld heat treatment,
which had caused “higher-than-normal microhardness tests.” As a result, the analysis found
inadequate toughness tests and inadequate shear requirement. There is no further analysis of
whether or to what extent those qualities could impact the susceptibility of the seam to failure.
In addition, even though the mill’s pipe specification license was considered, there was an
absence of manufacturing records for the segment to determine if these processes were actually
followed. Under the presumption that all pre-1970 ERW pipelines are susceptible to seam
failure unless otherwise shown, these issues should have weighed in favor of a conservative
conclusion regarding susceptibility absent further analysis.
Accordingly, I find the engineering analysis did not have sufficient support for concluding that
the SMI 6A to South Bend segment was not susceptible to longitudinal seam failure. For the
above reasons, I find the pipeline was operated out of compliance.
New Iberia to Sunset (Segment 7)
Respondent contended that this pipeline segment did not have to comply with the pressure
testing requirement in § 195.302 because Respondent had elected a risk-based alternative to
pressure testing under § 195.303. In addition, Respondent contended that the segment was
pressure tested in 1971-1973, and again in 2011 after the OPS inspection. Respondent explained
that the segment has now been purged of product and idled.
The documentation submitted by Respondent consisted of MOP inventory data sheets and emails
concerning a prospective tool run.35 These records do not demonstrate that Respondent had
evaluated the segment according to the risk factors in § 195.303 or that Respondent had assigned
a risk classification that exempted the segment from pressure testing.
33 Post-hearing Submission, Exhibit 6.
34 Post-hearing Submission, Exhibit 22.
35 Post-hearing Submission, Exhibits 32-35.



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No additional documentation was submitted to demonstrate the segment had been pressure tested
prior to the OPS inspection. Accordingly, I find this segment was not in compliance.
South Bend to New Iberia (Segment 8)
Respondent contended that this pipeline segment did not have to comply with the pressure
testing requirement in § 195.302 because Respondent had elected the risk-based alternative to
pressure testing. In addition, Respondent contended that the segment was pressure tested in 1972
and again in 2011 after the OPS inspection. Respondent noted that a portion of the segment is
currently idled.
The documentation submitted by Respondent consisted of MOP inventory data sheets.36 These
records do not demonstrate that Respondent had evaluated the segment according to the risk
factors in § 195.303 or that Respondent assigned a risk classification that exempted the segment
from pressure testing.
Respondent did not submit any additional documentation to show the segment had been pressure
tested prior to the OPS inspection. Accordingly, I find this segment was not in compliance.
Sunset to Anchorage (Segment 9)
Respondent contended that this pipeline segment did not have to comply with the pressure
testing requirement in § 195.302 because Respondent had elected the risk-based alternative to
pressure testing under § 195.303. In addition, Respondent contended that the segment was
pressure tested in 1971 and 1998. Respondent noted that the segment is currently idled.
The documentation submitted by Respondent consisted of MOP inventory data sheets and emails
concerning a prospective tool run.37 The records do not demonstrate Respondent had evaluated
the segment pursuant to § 195.303 or assigned a risk classification that exempted the segment
from pressure testing. In addition, Respondent did not submit documentation to show the
pipeline segment had been pressure tested prior to the OPS inspection. Accordingly, I find this
segment was not in compliance.
Borregas to Viola (Segment 20)
Respondent contended that this pipeline segment did not have to comply with the pressure
testing requirement because Respondent had elected the risk-based alternative to pressure testing.
In addition, Respondent contended that the segment was pressure tested in 2006.
Respondent did not submit any documentation to suggest Respondent had evaluated the segment
pursuant to a risk-based program that complied with § 195.303. In addition, the pressure test
36 Post-hearing Submission, Exhibits 36-39.
37 Post-hearing Submission, Exhibits 40-44.



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records submitted were missing necessary data, such as test pressure, duration, and
temperature.38 Accordingly, I find this segment was not in compliance.
e. Segments that Respondent Claimed Were Exempt from Part 195
Sarita to Borregas (Segment 17)
Respondent contended that the Sarita to Borregas pipeline segment is an unregulated gathering
line exempt from Part 195 (see § 195.1).
Respondent submitted supporting documentation to prove this segment is an unregulated
gathering line. Accordingly, this alleged violation is withdrawn.
SMI 6B to 6A (Segment 18)
Respondent contended that this pipeline segment was exempt from Part 195 because it was an
offshore pipeline located upstream of a production facility (see § 195.1(b)(5)). In addition,
Respondent noted that this segment was abandoned in 2007.
Respondent submitted supporting documentation to prove this segment was an offshore pipeline
upstream of a production facility, which is not subject to the requirements in § 195.302.
Accordingly, this alleged violation is withdrawn.
Texaco 11C to SMI 6B (Segment 26)
Respondent contended that this pipeline segment was exempt from Part 195 because it was an
offshore pipeline located upstream of a production facility. In addition, Respondent noted that
this segment was abandoned in 2007.
Respondent submitted supporting documentation to prove this segment was an offshore pipeline
upstream of a production facility, which is not subject to the requirements in § 195.302.
Accordingly, this alleged violation is withdrawn.
f. Additional Segment for Which Respondent Provided Records
Hawkins to MidValley Junction
This pipeline segment was not listed in the Spreadsheet, but Respondent introduced records for
the segment and contended that pressure testing was not required because the segment had been
“derated,” meaning MOP had been established under § 195.406(a)(5) based on 80 percent of the
highest operating pres
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