# EASTERN GAS TRANSMISSION AND STORAGE, INC. — Notice of Probable Violation

- **operation:** document
- **citation:** CPF 120091006
- **title:** EASTERN GAS TRANSMISSION AND STORAGE, INC. — Notice of Probable Violation
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2009-06-26
- **effective on:** Not available
- **summary:** CLOSED notice of probable violation citing 192.163(e), 192.179(c), 192.225(b), 192.481(a), 192.605, 192.709(c), 192.739(a), 192.743.
- **machine formats:** - **json:** https://regulus.evalyn.ai/document/phmsa-enforcement-120091006.json
- **markdown:** https://regulus.evalyn.ai/document/phmsa-enforcement-120091006.md
- **app url:** https://regulus.evalyn.ai/document/phmsa-enforcement-120091006
- **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/120091006
**body:**

Notice of Probable Violation involving EASTERN GAS TRANSMISSION AND STORAGE, INC.. PHMSA's enforcement data identifies the cited regulations as 192.163(e),  192.179(c),  192.225(b),  192.481(a),  192.605,  192.709(c),  192.739(a),  192.743. The case was opened on 2009-06-26 and is reported as closed as of 2011-12-20. Proposed civil penalty: $195,100. Assessed civil penalty: $191,500. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

120091006_ Supplement to Petition For Reconsideration_05262011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120091006/120091006_%20Supplement%20to%20Petition%20For%20Reconsideration_05262011.pdf

120091006_Closure Letter_12202011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120091006/120091006_Closure%20Letter_12202011.pdf

120091006_Closure Letter_12202011_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120091006/120091006_Closure%20Letter_12202011_text.pdf

120091006_Decision on the Petition for Reconsideration_10132011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120091006/120091006_Decision%20on%20the%20Petition%20for%20Reconsideration_10132011.pdf

120091006_Decision on the Petition for Reconsideration_10132011_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120091006/120091006_Decision%20on%20the%20Petition%20for%20Reconsideration_10132011_text.pdf

120091006_Final Order_ 12302010_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120091006/120091006_Final%20Order_%2012302010_text.pdf

120091006_FinalOrder_12302010.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120091006/120091006_FinalOrder_12302010.pdf

120091006_NOPV-PCP-PCO_06262009.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120091006/120091006_NOPV-PCP-PCO_06262009.pdf

120091006_NOPV-PCP-PCO_06262009_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120091006/120091006_NOPV-PCP-PCO_06262009_text.pdf

120091006_Operator Petition for Reconsideration_02232011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120091006/120091006_Operator%20Petition%20for%20Reconsideration_02232011.pdf

120091006_Operator Response_07292009.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120091006/120091006_Operator%20Response_07292009.pdf

120091006_NOPV-PCP-PCO_06262009_text.pdf

U.S. Department 820 Bear Tavern Road. Suite 306
of Transportation West Trenton, N.J. 08628
Pipeline and
Hazardous Materials
Safety Administration
NOTICE OF PROBABLE VIOLATION
PROPOSED CIVIL PENALTY
and
PROPOSED COMPLIANCE ORDER
CERTIFIED MAIL - RETURN RECEIPT REQUESTED
June 26, 2009
Mr. Jeff Barger
Vice President, Operations
Dominion Transmission, Inc.
445 West Main Street
Clarksburg, WV 26301
CPF 1-2009-1006
Dear Mr. Barger:
From July to November 2008, representatives of the Pipeline and Hazardous Materials Safety
Administration (PHMSA), the New York Public Service Commission, and the West Virginia
Public Service Commission pursuant to Chapter 601 of 49 United States Code inspected your
records and pipeline facilities in the states of West Virginia and Pennsylvania.
As a result of the inspection, it appears that you have committed probable violations of the
Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and the
probable violations are:



1. § 192.481 Atmospheric corrosion control: Monitoring
(a) Each operator must inspect each pipeline or portion of pipeline that is exposed
to the atmosphere for evidence of atmospheric corrosion, as follows:
If the pipeline is located:
Then the frequency of inspection is:
Onshore At least once every 3 calendar years, but with intervals
not exceeding 39 months
Offshore At least once each calendar year, but with intervals not
exceeding 15 months
Under § 192.481, DTI is required to inspect each portion of pipeline that is exposed to the
atmosphere at least once every three calendar years for onshore pipe for evidence of atmospheric
corrosion. DTI must perform these inspections at intervals not exceeding 39 months. However,
DTI failed to inspect the run #1 back-up fuel gas regulator station near valve FGV-25 at the
Oakford Compressor Station. The piping had surface rust and pits measuring up to 80 mils in
depth on a 5”x 8” area on top of the run. Also, atmospheric corrosion was found on the
dehydrator dry gas header outlet with pits measuring approximately 110 mils in depth at the
ground to air transition. Although DTI performed an atmospheric corrosion inspection in 2007,
it failed to identify these areas of atmospheric corrosion.
2. § 192.605 Procedural manual for operations, maintenance, and emergencies
(a) General. Each operator shall prepare and follow for each pipeline, a manual of
written procedures for conducting operations and maintenance activities and for
emergency response. For transmission lines, the manual must also include
procedures for handling abnormal operations. This manual must be reviewed and
updated by the operator at intervals not exceeding 15 months, but at least one each
calendar year. This manual must be prepared before operations of a pipeline
system commence. Appropriate parts of the manual must be kept at locations
where operations and maintenance activities are conducted.
(b) Maintenance and normal operations. The manual required by paragraph (a) of
this section must include procedures for the following, if applicable, to provide
safety during maintenance and operations.
(1) Operating, maintaining, and repairing the pipeline in accordance with each of
the requirements of this subpart and Subpart M of this part.
(2) Controlling corrosion in accordance with the operations and maintenance
requirements of Subpart I of this part.
2



DTI failed to follow its corrosion control maintenance requirements requiring drips to be blown
at least annually. DTI’s Standard Operating Procedures (SOP) Section 070/Corrosion Control,
SOP 15/Internal Corrosion states that all drips should be blown at least once each calendar year.
Maintenance records of the drips in the Oakford Fifth Sands and Murrysville Storage Pools show
that a total of 103 and 330 drips, respectively, from 2003 to 2007 were not blown annually to
remove fluids which can be corrosive to steel pipelines. Additionally, DTI has documented 69
drips which have not been blown because they cannot be accessed, cannot be blown and/or are
not piped up. These 69 additional drips are in a DTI schedule to be corrected within 9 years.
3. § 192.709 Transmission lines: Record keeping.
Each operator shall maintain the following records for transmission lines for the
periods specified:
c) A record of each patrol, survey, inspection, and test required by subparts L and
M of this part must be retained for at least 5 years or until the next patrol, survey,
inspection, or test is completed, whichever is longer.
DTI failed to provide records for the required last 5 years (2003-2007) to demonstrate that
annual capacity calculations were performed for pressure relieving devices at five compressor
stations (Harrison, Ellisburg, Stateline, Oakford and JB Tonkin) as required by §192.731 and
§192.743. DTI failed to provide to the PHMSA inspection team, during headquarter and field
inspections, compressor stations records showing the capacity review and calculations for their
relief devices. Although DTI reviews the initial capacity calculations as permitted by
§192.743(b) in order to meet the annual capacity determination requirements for relief devices,
DTI is still required to demonstrate that the parameters have not changed to avoid subsequent
calculations. DTI could not provide records to demonstrate this required review of the
parameters was performed.
4. § 192.739 Pressure limiting and regulating stations: Inspection and testing.
(a) Each pressure limiting station, relief device (except rupture discs), and pressure
regulating station and its equipment must be subjected at intervals not exceeding 15
months, but at least once each calendar year, to inspections and tests to determine
that it is—
(1) In good mechanical condition;
(2) Adequate from the standpoint of capacity and reliability of operation for the
service in which it is employed;
3



(3) Except as provided in paragraph (b) of this section, set to control or relieve at
the correct pressure consistent with the pressure limits of §192.201(a); and
(4) Properly installed and protected from dirt, liquids, or other conditions that
might prevent proper operation.
During PHMSA’s field inspection, DTI technicians stated that some relief devices had not been
inspected and no records of inspection were in the DTI’s database. The following relief valves
were not inspected at the required intervals for the period of 2003-2007:
1. Ellisburg Compressor Station fuel gas bottle inlet 1st cut regulator (Location ID
CSN6361) has a regulator but the overpressure protection was not listed as inspected
2. Ellisburg Compressor Station relief valve (2” Axelson serial number 632280)
3. Stateline Compressor Station fuel gas bypass relief valve
5. §192.743 Pressure limiting and regulator stations: Capacity of relief devices.
(a) Pressure relief devices at pressure limiting stations and pressure regulating
stations must have sufficient capacity to protect the facilities to which they are
connected. Except as provided in §192.739(b), the capacity must be consistent with
the pressure limits of §192.201(a). This capacity must be determined at intervals not
exceeding 15 months, but at least once each calendar year, by testing the devices in
place or by review and calculations
(b) If review and calculations are used to determine if a device has sufficient
capacity, the calculated capacity must be compared with the rated or experimentally
determined relieving capacity of the device for the conditions under which it
operates. After the initial calculations, subsequent calculations need not be made if
the annual review documents that parameters have not changed to cause the rated
or experimentally determined relieving capacity to be insufficient.
DTI failed to conduct adequate annual reviews of pressure relieving devices to determine
sufficient capacity at the five pressure limiting station devices noted below. DTI only physically
checked the relief devices for pressure set point and operation. DTI did not determine adequate
relief capacity. DTI had no documentation showing capacity calculations for the relief devices
including comparison to rated relief design at their facilities needed for the required annual relief
capacity determination.
1) Stateline Compressor Station location, feed line #16 with 1st and 2nd regulator stations
with 2” Welmark relief valve
4



2) Stateline Compressor Station location Line #24 supplied by 10” dual port regulator
with overpressure protection provided by 8”relief valve having a 6” inlet pipe
3) Oakford Region, Gas sales to Peoples Gas having a 6”x 8” Axelson relief valve
4) Oakford Region, Springdale meter and regulator station with relief valve overpressure
protection
5) Mockingbird Hill Station #426 regulator and relief assembly
6. § 192.225 Welding procedures.
(a) Welding must be performed by a qualified welder in accordance with welding
procedures qualified under section 5 of API 1104 (incorporated by reference, see
§192.7) or section IX of the ASME Boiler and Pressure Vessel Code “ Welding and
Brazing Qualifications” (incorporated by reference, see §192.7) to produce welds
meeting the requirements of this subpart. The quality of the test welds used to
qualify welding procedures shall be determined by destructive testing in accordance
with the applicable welding standard(s).
(b) Each welding procedure must be recorded in detail, including the results of the
qualifying tests. This record must be retained and followed whenever the procedure
is used.
During the field inspection of the Cove Point MD expansion project, DTI representatives
indicated that there were no welding repair procedures on site in accordance with welding
procedures qualified by §192.225; and, that welding repairs had been made to the DTI project
facilities without having qualified procedures.
7. § 192.179 Transmission line valves.
(c) Each section of a transmission line, other than offshore segments, between main
line valves must have a blowdown valve with enough capacity to allow the
transmission line to be blown down as rapidly as practicable. Each blowdown
discharge must be located so the gas can be blown to the atmosphere without hazard
and, if the transmission line is adjacent to an overhead electric line, so that the gas is
directed away from the electrical conductors.
5



DTI did not determine if the new 36” transmission line being installed for the Cove Point, MD
expansion project could be blown down as rapidly as practicable as required by §192.179(c).
DTI indicated that the Cove Point, MD expansion project blow-down design was made to match
the blow-down design of the existing Cove Point parallel 30” transmission line. DTI did not take
into consideration the larger size (36”) of the new main, and just assumed the existing 30”
transmission line blow-down capacity would be sufficient.
8. § 192.163 Compressor stations: Design and construction.
(e) Electrical facilities. Electrical equipment and wiring installed in compressor
stations must conform to the National Electrical Code, ANSI/NFPA 70, so far as
that code is applicable.
DTI did not conform to the National Electrical Code requirements. At the time of the inspection,
DTI transformers adjacent to main compressor building at Lightburn Station did not appear to be
tied into a continuous grounding circuit in explosion-proof boxes, in accordance with NFPA 70
(2005) National Electrical Code, Article 250, for the following equipment:
(1) #5 engine pre-lube pump starter
(2) #4 engine pre-lube pump starter
(3) #3 engine pre-lube pump starter.
Proposed Civil Penalty
Under 49 United States Code, § 60122, you are subject to a civil penalty not to exceed $100,000
for each violation for each day the violation persists up to a maximum of $1,000,000 for any
related series of violations. The Compliance Officer has reviewed the circumstances and
supporting documentation involved in the above probable violations and has recommended that
you be preliminarily assessed a civil penalty of $195,100 as follows:
Item number
PENALTY
Item 1 $30,500
Item 2 $80,500
Item 3 $16,800
Item 4 $36,800
Item 5 $30,500
Warning Items
6



With respect to Items 6, 7 and 8, 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 items. Be advised
that failure to do so may result in Dominion Transmission, Inc. being subjected to additional
enforcement action.
Proposed Compliance Order
With respect to Item 2 pursuant to 49 United States Code § 60118, the Pipeline and Hazardous
Materials Safety Administration proposes to issue a Compliance Order to Dominion
Transmission, Inc. Please refer to the Proposed Compliance Order, which is enclosed and made
a part of this Notice.
Response to this Notice
Enclosed as part of this Notice is a document entitled Response Options for Pipeline Operators
in Compliance Proceedings. Please refer to this document and note the response options. Be
advised that all material you submit in response to this enforcement action is subject to being
made publicly available. If you believe that any portion of your responsive material qualifies for
confidential treatment under 5 U.S.C. 552(b), along with the complete original document you
must provide a second copy of the document with the portions you believe qualify for
confidential treatment redacted and an explanation of why you believe the redacted information
qualifies for confidential treatment under 5 U.S.C. 552(b). If you do not respond within 30 days
of receipt of this Notice, this constitutes a waiver of your right to contest the allegations in this
Notice and authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in
this Notice without further notice to you and to issue a Final Order.
In your correspondence on this matter, please refer to CPF 1-2009-1006 and for each document
you submit, please provide a copy in electronic format whenever possible.
Sincerely,
Byron E. Coy, P.E.
Director, Eastern Region
Pipeline and Hazardous Materials Safety Administration
Enclosures: Proposed Compliance Order
Response Options for Pipeline Operators in Compliance Proceedings
7



PROPOSED COMPLIANCE ORDER
Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety
Administration (PHMSA) proposes to issue to Dominion Transmission, Inc.(DTI) a Compliance
Order incorporating the following remedial requirements to ensure the compliance of DTI with
the pipeline safety regulations:
1. In regard to Item Number 2 of the Notice, DTI must provide documentation that
substantiates that all the drips in the Oakford Fifth Sands and Murrysville Storage
Pools that can currently be blown down have been blown down within 180 days
of date of final order.
2. In reference to Item Number 2, the 69 documented drips which have not been
blown per DTI standard operating procedures (SOP), DTI must develop and
execute a plan to find, make accessible, and modify as needed for drip blowing
operations, those 69 identified drips within 365 days of date of final order.
3. DTI shall submit the results of the Proposed Compliance Order items above to the
Director, Eastern Region, Office of Pipeline Safety, Pipeline and Hazardous
Materials Safety Administration,
4. DTI shall maintain documentation of the safety improvement costs associated
with fulfilling this Compliance Order and submit the total to Director, Eastern
Region, Pipeline and Hazardous Materials Safety Administration. Costs shall be
reported in two categories: 1) total cost associated with preparation/revision of
plans, procedures, studies and analyses, and 2) total cost associated with
replacements, additions and other changes to pipeline infrastructure.
8

120091006_Closure Letter_12202011_text.pdf

U.S. Department 820 Bear Tavern Road, Suite 103
Of Transportation West Trenton, NJ 08628
Pipeline and 609.989.2171
Hazardous Materials
Safety Administration
EXPRESS OVERNIGHT DELIVERY
December 20, 2011
Mr. Jeff Barger
Vice President, Operations
Dominion Transmission, Inc.
445 West Main Street
Clarksburg, WV 26301
CPF 1-2009-1006
Dear Mr. Barger:
On December 30, 2010, the Pipeline and Hazardous Materials Safety Administration (PHMSA)
issued to Dominion Transmission, Inc. (DTI) a Final Order in the above-referenced case. This
Order included a Compliance Order and Civil Penalty assessment.
After receiving an extension of time, DTI submitted to PHMSA, by letter dated February 23,
2011, a Petition for Reconsideration of the Order (Petition).
DTI submitted, by letter dated February 28, 2011, interim results for Compliance Order Items 1
and 2 (per the terms of Item 3 in the Compliance Order) to the Director, PHMSA Eastern Region
(Director). For Compliance Order Item 2, DTI was required to submit a plan for drip blowing
operations to the Director, within 60 days of the Final Order (and execution of the plan within
365 days of the Final Order). DTI submitted test results in lieu of a plan. The Director accepted
the test results in lieu of a plan.
DTI supplemented its Petition to PHMSA by letter dated May 26, 2011.
DTI submitted a letter dated July 29, 2011 with additional Compliance Order related results to
the Director. In that letter, DTI:



120091006
• Provided safety related costs associated with Compliance Order Item 4.
• Updated the results for Compliance Order Items 1 and 2.
• Inadvertently referred to an incorrect date for submission of plans for Compliance Order
Item 2. DTI stated February 14, 2011, which should have been February 28, 2011.
PHMSA issued its decision on the Petition in the above referenced case on October 13, 2011.
The Petition was denied.
DTI subsequently paid the civil penalty amount via wire transfer on October 27, 2011.
DTI submitted a letter to the Director on November 18, 2011, noting that the one previously
remaining inoperable drip within its Oakford Storage Field had been successfully blown on
October 28, 2011.
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,
Byron Coy, PE
Director, Eastern Region
Pipeline and Hazardous Materials Safety Administration
120091006_Closure Letter_12202011 Page 2 of 2

120091006_FinalOrder_12302010.pdf

U.S. Department
of Transportation
Washington, DC 20590
1200 New Jersey Ave., SE
Safety Administration
Pipeline and Hazardous Materials
DEC 3 0 2010
Mr. Jeff Barger
Vice President, Operations
Dominion Transmission, Inc.
445 West Main Street
Clarksburg, WV 26301
Re: CPF No. 1-2009-1006
Dear Mr. Barger:
Enclosed please find the Final Order issued in the above-referenced case. It withdraws several
instances of alleged violations, makes other findings of violation, and assesses a reduced civil
penalty of $191,500. The Order also specifies actions that need to be taken by Dominion
Transmission, Inc. to comply with the pipeline safety regulations. When the civil penalty has
been paid and the terms of the compliance order are completed, as determined by the Director,
Eastern 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. Byron E. Coy, Director, Eastern Region, PHMSA
CERTIFIED MAIL - RETURN RECEIPT REQUESTED |7005 1160 0001 0039 99831



U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, D.C. 20590
In the Matter of
Dominion Transmission, Inc.
CPF No. 1-2009-1006
Respondent.
FINAL ORDER
Between July-November 2008, pursuant to 49 U.S.C. § 60117, representatives of the Pipeline
and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), the
New York Public Service Commission, and the West Virginia Public Service Commission,
conducted a series of on-site pipeline safety inspections of the facilities and records of Dominion
Transmission, Inc. (DTI or Respondent) at its headquarters in Clarksburg, WV, and its field
facilities in Oakford, PA, Harrison Valley, PA, Ellisburg, PA, State Line, PA, Lightburn Station,
WV, and Cove Point, MD. Respondent operates approximately 3,649 miles of gas transmission
pipeline throughout West Virginia, Ohio, Pennsylvania, New York, Maryland, and Virginia.
As a result of the inspection, the Director, Eastern Region, OPS (Director), issued to Respondent,
by letter dated June 26, 2009, a Notice of Probable Violation, Proposed Civil Penalty, and
Proposed Compliance Order (Notice). In accordance with 49 C.F.R. § 190.207, the Notice
proposed finding that DTI had committed various violations of 49 C.F.R. Part 192, proposed a
civil penalty of $195,100, and proposed that Respondent be required to take certain measures to
correct the alleged violations.
DTI responded to the Notice by letter dated July 29, 2009 (Response). Respondent contested
some of the allegations, offered additional information in response to the Notice, and requested
the withdrawal or the mitigation of certain proposed civil penalties. Respondent did not request
a hearing and therefore has waived its right to one.
FINDINGS OF VIOLATION
The Notice alleged that Respondent violated 49 C.F.R. Part 192, as follows:
Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 192.481(a), which states:



2
§ 192.481 Atmospheric Corrosion control: Monitoring.
(a) Each operator must inspect each pipeline or portion of pipeline
that is exposed to the atmosphere for evidence of atmospheric corrosion,
as follows.
If the pipeline is
Then the frequency of
located:
Onshore
......
At least once every 3 calendar years, but with
intervals not exceeding 39 months.
Offshore ............
At least once each calendar year, but with
intervals not exceeding 15 months.
The Notice alleged that Respondent violated 49 C.F.R. § 192.481(a) by failing to inspect each
intervals not exceeding 39 months. Specifically,
nerval not exceeding exceeding exposes. Specifically, the Notice allege that bre failed dar near ahe
run #1 back-up fuel gas regulator station near valve FGV-25 at the Oakford Compressor Station.
The Notice further alleged that Respondent failed to identify areas of atmospheric corrosion on
the dehydrator dry gas outlet.
In its Response, DTI contended that it did make efforts to identify the corrosion on this
dehydrator dry gas outlet and scheduled it for maintenance. However, DTI also noted that the
remediation did not fully comply with its own procedures. Further, DTI conceded that it
overlooked the inspection for the fuel gas piping in the vicinity of valve FGV-25 during its 2007
Atmospheric Corrosion inspection.
As Respondent admitted, its maintenance efforts were insufficient and it failed to inspect a
portion of its pipeline for atmospheric corrosion within three calendar years. While I
acknowledge DTT's efforts to identify the corrosion on its dehydrator dry gas outlet and schedule
it for maintenance, it is clear that DTI did not fully comply with the requirements under
§ 192.481(a) by overlooking the inspection of the run #1 back-up fuel gas regulator station near
valve FGV-25 at the Oakford Compressor Station.
Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49
C.F.R. $ 192.481(a) by failing to inspect each portion of pipeline that is exposed to the
atmosphere at least once every three calendar years, and at intervals not exceeding 39 months.
Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 192.605, which states:
§ 192.605 Procedural manual for operations, maintenance, and
emergencies.
(a) General. Each operator shall prepare and follow for each pipeline,
a manual of written procedures for conducting operations and maintenance
activities and for emergency response. For transmission lines, the manual
must also include procedures for handling abnormal operations. This
manual must be reviewed and updated by the operator at intervals not
exceeding 15 months, but at least once each calendar year. This manual
must be prepared before operations of a pipeline system commence.



3
Appropriate parts of the manual must be kept at locations where
operations and maintenance activities are conducted.
(b) Maintenance and normal operations. The manual required by
paragraph (a) of this section must include procedures for the following, if
(2) Controlling corrosion in accordance with the operations and
maintenance requirements of subpart I of this part....
The Notice alleged that Respondent violated 49 C.F.R. § 192.605 by failing to follow its
corrosion control maintenance procedure requiring drips to be blown at intervals not exceeding
one calendar year. Specifically, it alleged that, at the time of the inspection, 103 and 330 drips
had not been blown annually at the Oakford Fifth Sands and Murrysville Storage Pools,
respectively, from 2003 through 2007.
In its Response, DTI did not contest this allegation of violation, but contended that the two
locations only have a total of 331 drips, rather than 433 as alleged in the Notice. Respondent
stated that all of the operable drips can be or have been blown in the past year.
PHMSA agrees with DTT's contention that there are only 331 drips at the Oakford Fifth Sands
and Murrysville Storage Pools collectively. PHMSA further concedes that Respondent's drips
can be or have been blown in the past year. However, these contentions do not rebut the
allegation that DTI failed to blow 443 drips annually between 2003 and 2007. To clarify, the
Notice cited DTI for a total of 433 instances of drips not being blown during the time period in
question, including some of the same drips that were not blown in multiple years.!
Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49
C.F.R. § 192.605 by failing to follow its corrosion control maintenance procedure requiring drips
to be blown at intervals not exceeding one calendar year.
Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 192.709(c), which states:
§ 192.709 Transmission lines: Record keeping.
Each operator shall maintain the following records for transmission
lines for the periods specified.
(a)
(c) A record of each patrol, survey, inspection, and test required by
subparts L and M of this part must be retained for at least 5 years or until
the next patrol, survey, inspection, or test is completed, whichever is
longer.
The Notice alleged that Respondent violated 49 C.F.R. § 192.709(c) by failing to maintain
records required by subparts L and M. Specifically, it contended that DTI was unable to provide
' Violation Report, Exhibit B.



4
records from calendar years 2003 through 2007 to demonstrate that annual capacity calculations
were performed for pressure relieving devices at five compressor stations (Harrison, Ellisburg,
Stateline, Oakford and JB Tonkin).
In its Response, DTI contested this allegation of violation. Respondent stated that it had
recorded each annual review in either spreadsheets or through an electronic Inspection
Monitoring System (IMS). In its Response, DTI provided an example of its IMS, but it did not
include the full records of the capacity calculations. Nor did DTI provide any explanation for its
inability to furnish the documents during the PHMSA inspection.
The evidence in the record demonstrates that Respondent's Compliance Engineer could not
locate records of relief valve capacity determinations for the subject years during the inspection
even though PHMSA had notified the company prior to the inspection that such records would
be requested. In its Response, DTI did not dispute that it could not provide the PHMSA
inspection team with records of the capacity calculations for relief devices, and despite the
amount of time since the inspection in 2008, has not provided all of the required records to
PHMSA.
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 192.709(c) by failing to maintain records demonstrating that annual capacity calculations were
performed for pressure relieving devices at five of DTT's compressor stations.
Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 192.739(a), which states:
§ 192.739 Pressure limiting and regulating stations: Inspection and
testing.
(a) Each pressure limiting station, relief device (except rupture discs),
and pressure regulating station and its equipment must be subjected at
intervals not exceeding 15 months, but at least once each calendar year, to
inspections and tests to determine that it is-
(1) In good mechanical condition;
(2) Adequate from the standpoint of capacity and reliability of
operation for the service in which it is employed;
(3) Except as provided in paragraph (b) of this section, set to control
or relieve at the correct pressure consistent with the pressure limits of
§ 192.201(a); and
(4) Properly installed and protected from dirt, liquids, or other
conditions that might prevent proper operation.
2 Respondent stated in its Response that the records were not included because they constituted "hundreds of
does not explain the company's failure to maintain the records for inspection. Furthermore, the Notice clearly
pages," but that they could be furnished upon request. Response at 3. Even if the records had been provided, that
explained to DTI that the existence of these records was in dispute, and therefore Respondent should have provided
all of them to rebut the allegation.
3 Violation Report at 7-8.



5
The Notice alleged that Respondent violated 49 C.F.R. § 192.739(a) by failing to perform
inspections and tests at intervals not exceeding 15 months, but at least once each calendar year,
on several relief devices. Specifically, the Notice alleged that DTI failed to inspect the following
relief valves: (1) the Ellinsburg Compressor Station fuel gas bottle inlet 1st cut regulator
(Location ID CSN6361); (2) the Ellinsburg Compressor Station relief valve (2" Axelson serial
no. 632280); and (3) the Stateline Compressor Station fuel gas bypass relief valve.
In its Response, DTI did not contest the allegations of violation with regard to the two devices at
Ellinsburg Compressor Station listed above, but contested the allegation of violation with regard
to the device at Stateline Compressor Station, which the company argued is a secondary form of
protection, personally operated by DTI employees. Due to the nature of the Stateline
Compressor Station device, Respondent asserted that it is not subject to the requirements of relief
devices under 49 C.F.R. § 192.739.
PHMSA agrees with DTT's characterization of the relief valve at the Stateline Compressor
Station listed in its Response. The valve is only a secondary form of protection and therefore is
not covered by the testing and inspection requirements of 49 C.F.R $ 192.739.* However, DTI
did not contest that it failed to test and inspect the two (2) devices at the Ellinsburg Compressor
Station at intervals not exceeding 15 months, but at least once each calendar year.
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R
§ 192.739 by failing to test each of its relief devices at the required intervals.
Item 5: The Notice alleged that Respondent violated 49 C.F.R. § 192.743, which states:
§ 192.743 Pressure limiting and regulator stations: Capacity of relief
devices.
(a) Pressure relief devices at pressure limiting stations and pressure
regulating stations must have sufficient capacity to protect the facilities to
which they are connected. Except as provided in § 192.739(b), the
capacity must be determine at intervals not exceeding 15 months, but at
least once each calendar year, by testing the devices in place or by review
and calculations.
(b) If review and calculations are used to determine if a device has
sufficient capacity, the calculated capacity must be compared with the
rated or experimentally determined relieving capacity of the device for the
conditions under which it operates. After the initial calculations,
subsequent calculations need not be made if the annual review documents
that parameters have not changed to cause the rated or experimentally
determined relieving capacity to be insufficient.
* PHMSA has not interpreted § 192.739 to apply to set points and capacities of back-up or secondary over-pressure
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reading-room.



The Notice alleged that Respondent violated 49 C.F.R. § 192.743 by failing to determine, at
intervals not exceeding 15 months and at least once each calendar year, that the pressure relief
devices at pressure limiting stations and pressure regulating stations had sufficient capacity to
protect the facilities to which they are connected. Specifically, the Notice alleged that DTI failed
to conduct the required tests of the pressure relieving devices at the following five pressure
limiting stations: (1) Stateline Compressor Station location, feed line #16 with Ist and 2nd
regulator stations with 2" Welmark relief valves; (2) Stateline Compressor Station location Line
#24 supplied by 10" dual port regulator with overpressure protection provided by 8" relief valve
having a 6" inlet pipe; (3) Oakford Region, Gas sales to People Gas having a 6" x 8" Axelson
relief valve; (4) Oakford Region, Springdale meter and regulator station with relief valve
overpressure protection; and (5) Mockingbird Hill Station #426 regulator and relief assembly.
In its Response, DTI did not contest the allegations of violation with regard to the two devices at
the Stateline Compressor Station, but contended that the testing requirements under 49 C.F.R.
§ 192.743 did not apply to the other three devices listed in the Notice. First, Respondent stated
that the relief device for "Oakford Region, Gas sales to People Gas" is not an overprotection
device, and therefore it is not covered by § 192.743. Second, DTI asserted that the device at
"Oakford Region, Springdale meter and regulator station" is protected manually by company
personnel rather than a relief device. Third, DTI noted that the listed device for "Mockingbird
Hill Station" is secondary protection; the primary protection for the station is a high pressure
shutdown switch on the compressor engine.
PHMSA agrees with Respondent's assertions. The three devices addressed by DTI are not
covered by 49 C.F.R. § 192.743. Therefore, DTI was not obligated to perform the tests
prescribed under the regulation. However, Respondent did not contest that it failed to perform
the required tests on (1) the Stateline Compressor Station location, feed line #16 with 1st and 2nd
regulator stations with 2" Welmark relief valves; and (2) the Stateline Compressor Station
location Line #24 supplied by 10" dual port regulator with overpressure protection provided by
8" relief valve having a 6" inlet pipe.
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 192.743 by failing to determine, at intervals not exceeding 15 months and at least once each
calendar year, that each of its pressure relief devices at pressure limiting stations and pressure
regulating stations had sufficient capacity to protect the facilities to which they are connected.
These findings of violation will be considered prior offenses in any subsequent enforcement
action taken against Respondent.
ASSESSMENT OF PENALTY
Under 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed
$100,000 per violation for each day of the violation, up to a maximum of $1,000,000 for any
related series of violations.
In determining the amount of a civil penalty under 49 U.S.C. § 60122 and 49 C.F.R. § 190.225, I
must consider the following criteria: the nature, circumstances, and gravity of the violation,



7
including adverse impact on the environment; the degree of Respondent's culpability; the history
of Respondent's prior offenses; the Respondent's ability to pay the penalty and any effect that
the penalty may have on its ability to continue doing business; and the good faith of Respondent
in attempting to comply with the pipeline safety regulations. In addition, I may consider the
economic benefit gained from the violation without any reduction because of subsequent
damages, and such other matters as justice may require. The Notice proposed a total civil
penalty of $194,500 for the violations cited above.
Item 1: The Notice proposed a civil penalty of $30,500 for Respondent's violation of 49 C.F.R.
§ 192.481, for failing to inspect a regulator station near valve FGV-25 at the Oakford
Compressor Station for evidence of atmospheric corrosion. DTI contended that it made some
effort to identify and remediate the corrosion on the dehydrator dry gas header outlet.
Although PHMSA agrees that Respondent made an effort to identify corrosion, schedule
remediation, and make an effort to complete the remediation before the time of the PHMSA
inspection, DTI failed to remediate the corrosion properly. As DTI admitted, the below-ground
coating did not extend above 
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