I202604 NOPV Response (2)

EXECUTIVE OFFICES
INTERMOUNTAIN GAS COMPANY
555 SOUTH COLE ROAD-P.O.BOX 7608• BOISE,IDAHO 83707•[phone]• FAX:[phone]
May 28,2026
Mr.Jeff Brooks,Programs Manager
Idaho Public Utility Commission
PO Box 83720
Boise,ID 83720-0074
Subject:Response to the Notice of Probable Violation dated April 16,2026(Report#I202604)
Dear Mr.Brooks,
This letter is intended to address one(1)notice of probable violation stemming from a sample damage prevention
and line marker audit conducted by the Idaho Public Utilities Commission(IPUC)on April 16,2026,of
Intermountain Gas Company's(IGC)Nampa District pursuant to Chapter 601,Title 49,United States Code.
PROBABLE VIOLATION
1. 49 CFR 8 192.605 Procedural Manual for Operations. Maintenance. and Emergencies
(a) General. Each operator shall prepare and follow for each pipeline,a manual of written procedures
for conducting operations and maintenance activities and for emergency response.For transmission
lines,the manual must also include procedures for handling abnormal operations.This manual must
be reviewed and updated by the operator at intervals not exceeding 15 months,but at least once each
calendar year.This manual must be prepared before operations of a pipeline system commence.
Appropriate parts of the manual must be kept at locations where operations and maintenance
activities are conducted.
49 CFR 8 192-703 General
(a)No person may operate a segment of pipeline,unless it is maintained in accordance with this
subpart.
2. 49 CFR § 192,1007 What are the required elements of an integrity management In an?
(b)Identify threats.The operator must consider the following categories of threats to each gas
distribution pipeline: corrosion(including atmospheric corrosion),natural forces,excavation damage,
other outside force damage,material or welds,equipment failure,incorrect operations,and other issues
that could threaten the integrity of its pipeline.An operator must consider reasonably available
information to identify existing and potential threats.Sources of data may include incident and leak
history,corrosion control records(including atmospheric corrosion records),continuing surveillance
records,patrolling records,maintenance history,and excavation damage experience.
(c)Evaluate and rank risk.An operator must evaluate the risks associated with its distribution pipeline.
In this evaluation,the operator must determine the relative importance of each threat and estimate and
rank the risks posed to its pipeline.This evaluation must consider each applicable current and potential
threat,the likelihood of failure associated with each threat,and the potential consequences of such a
failure.An operator may subdivide its pipeline into regions with similar characteristics(e.g.,
contiguous areas within a distribution pipeline consisting of mains, services and other appurtenances;
areas with common materials or environmental factors),and for which similar actions likely would be
effective in reducing risk.
OPS 705 Gas Pipeline Markers and Signs Installation and Inspection
5.INSPECTION AND MAINTENANCE
5.1.Pipeline markers shall be inspected at least every five(5)years,not to exceed 63 months.
Pipeline markers shall be inspected and documented during leak surveys in accordance with
OPS 706—Leak Survey.
5.5.Pipeline markers and signs shall be inspected for damage and overgrowth that may obscure
their visibility.Damaged,worn out,or missing signs shall be marked as a deficiency

EXECUTIVE OFFICES
INTERMOUNTAIN GAS COMPANY
555 SOUTH COLE ROAD-P.O.BOX 7608• BOISE,IDAHO 83707•[phone]•FAX:[phone]
5.6. During the survey/inspection of signs and pipeline markers,the surveyor(s) shall ensure that
pipeline markers and signs have the following,written legibly on the sign or pipeline marker
(not applicable for Waterway Crossing or Deterrent Custom Signage):
5.6.1. "Caution," "Warning,"or"Danger"followed by"Gas Pipeline"or"Natural Gas
Pipeline"in letters at least one(1")inch high with one-fourth('/a")inch stroke.
5.6.2. The appropriate MDUG organization and emergency phone number:
5.7. The pipeline marker or sign shall have a background of sharply contrasting color so that the
information stated on the sign or marker is easily visible.
OPS 1000 Distribution integrity Management
3.2.3. Excavation Damage
Excavation damage is damage to pipeline facilities caused by earth moving or other
equipment,tools,or vehicles,including damage done by operator's personnel,
contractor,or people not associated with the operator.All buried facilities in MDUG's
distribution system face the threat of being damaged by excavation activities.
Consideration is given to piping within protective casings,inside underground
structures such as basins or vaults which may be shielded or protected from
excavation damage.Excavation damage can also be due to previous unknown
damage on pipelines that were not repaired and result in corrosion.
5.1. Overview
This section describes the existing and proposed measures to address the threats and
associated risk to MDUG's distribution system as outlined in Sections 3.0: Threat Identification
and 4.0: Risk Evaluation and Ranking.
Risk management is accomplished by taking actions to reduce the likelihood of an occurrence,
by alleviating the consequences of an occurrence or both.Appropriate actions are dependent
on the group being addressed,the associated threat,whether the threat is current or potential
in the future,and the viability of the actions in managing the relevant risk factors.
5.2. Existing Programs Addressing Risk Management
This section summarizes existing plans and programs implemented by MDUG that are
currently in place to manage risks.Each established program contributes to the management
and mitigation of risk to the distribution system.Details for each program are contained in
MDUG O&M procedures and are available upon request.
5.2.1. Damage Prevention
The prevention of damage to natural gas distribution facilities by excavation is one of
the most effective ways of increasing the integrity of the gas system and improving
public safety relative to natural gas.MDUG has implemented and maintains a
Damage Prevention Program,OPS 614,that meets the following criteria:
•Meets or exceeds the requirements of§192.614—Damage Prevention Program.
•Participates in One-Call programs within service territory.
• Supports the Common Ground Alliance(CGA)efforts to reduce excavation
damage through the publication and dissemination of best practices.

EXECUTIVE OFFICES
INTERMOUNTAIN GAS COMPANY
555 SOUTH COLE ROAD-P.O.BOX 7608• BOISE,IDAHO 83707•[phone]•FAX:[phone]
OPS 610 Pipeline Patrolling and Continuing Surveillance
2.2.4.Pipeline markers are installed, visible, and legible with correct contact information.
OPS 403 Section 2 INSPECTION CRITERIA
2.13.Inspect pipeline markers.
2.13.1. Inspection includes the condition of existing pipeline marker or the need to add a
pipeline marker(s)for better visibility of the HPSS or farm tap. Examples include the
following:
2.13.1.1. In the ROW or near high traffic areas.
2.13.1.2. In vegetation that obscures visibility.
2.15. Inspect pipeline markers.
2.15.1. Inspection includes the condition of existing pipeline marker(s)or the need to add a
pipeline marker(s)for better visibility of the meter set,HPSS, or farm tap.
2.15.2. Check that pipeline markers are visible and legible with correct contact information.
Findinu(s)•
Staff identified—37 pipeline markers that were missing,damaged,faded,or otherwise illegible,resulting in
noncompliance with required visibility and identification standards for underground pipelines.In addition,locate
wires were found disconnected within multiple Maloney posts,preventing proper tracing and identification of the
buried pipeline facilities.
See Exhibit A below for example photographs and GPS-referenced locations of the affected markers and Maloney
posts.
Intermountain Gas Response
IGC respectfully disputes that this finding constitutes as a violation of 49 CFR§192.1007.
49 CFR §192.1007 establishes requirements for Distribution Integrity Management Programs (DIMP), including
threat identification (§192.1007(b)) and risk evaluation and ranking (§192.1007(c)), as referenced above. These
elements are fully addressed within Sections 3 and 4 of OPS 1000—Distribution Integrity Management Plan.
Per 49 CFR§192.1007(d),a written plan must also"[d]etermine and implement measures designed to reduce the risks
from failure of its gas distribution pipeline."DIMP is inherently structured to leverage existing operational controls
to reduce risk, such as surveillance, patrolling, and maintenance programs. Utilizing existing operational controls
meets the requirements of identifying and implementing a measure to address risk.The text of the regulation does not
provide that non-conformance of an operating control, in itself, establishes an inadequate DIMP program, or that it
fails to meet the requirements of 49 CFR§192.1007.
Furthermore,pipeline markers are governed by 49 CFR§192.707.OPS 403—Atmospheric Corrosion and Monitoring
applies to the AC Survey of meter set assemblies,high pressure service sets,(HPSS),and farm taps. OPS 304-High
Pressure Service Set(HPSS)and Farm Tap Inspection&Maintenance applies to HPSS and farm taps within the IGC
system. OPS 403 and OPS 304,as referenced above,do not apply to main or transmission lines.
Although IGC respectfully disputes this finding as it relates to DIMP,IGC is aware of and acknowledges the systemic
issue regarding the maintenance of pipeline markers. As such, IGC has developed a plan for conducting a
comprehensive review of all districts to verify where required pipeline markers currently exist and determine where
required pipeline markers may need to be installed.IGC's Field Operations department will begin with a desktop GIS
review to verify required locations per OPS 705 — Gas Pipeline Markers and Signs Installation Inspection and
Maintenance. The GIS review will be completed by end of year 2026. In conjunction with the GIS review, IGC's
Operations Systems Programs department has begun program development within its compliance tracking software
application. Going forward, required pipeline marker locations will be individually mapped and maintained within
GIS,and pipeline marker surveys will be documented as a standalone survey in the tracking software. Following the
GIS review and program development, the locations identified during the GIS review will be physically verified in

EXECUTIVE OFFICES
INTERMOUNTAIN GAS COMPANY
555 SOUTH COLE ROAD-P.O.BOX 7608•BOISE,IDAHO 83707•[phone]•FAX:[phone]
the field.The field verification will begin in 2027 and will take place over a five year period during existing scheduled
pipeline marker surveys as required by OPS 705.Existing pipeline markers will be inspected for damage,overgrowth
that may obscure visibility,and legibility.New pipeline markers,if missing,will be installed at the required locations.
Additional training will be provided immediately to personnel responsible for maintaining pipeline markers,followed
by subsequent training on the new survey process prior to commencement of the 2027 pipeline marker survey.
The pipeline markers identified by the IPUC have been updated with new decals(see Attachment 1).
Additionally,per OPS 407—Exothermic Welding Connections to Steel Pipelines section 3.19."Conductor wire shall
be installed to the test station." The intent of this section is to ensure that wires are present at the test station (e.g.,
Maloney post). While the wires do not have to be connected to perform needed tasks, such as locate the facilities,
training will be provided to personnel who perform line locates on connecting test leads,ifneeded,after the completion
of a line locate.
Please contact Josh Sanders at(701)222-7773 with questions or comments.
Respectfully Submitted,
Pat Darras
Vice President, Engineering& Operations Services
Intermountain Gas Company

EXECUTIVE OFFICES
INTERMOUNTAIN GAS COMPANY
555 SOUTH COLE ROAD-P.O.BOX 7608• BOISE,IDAHO 83707•[phone]• FAX:[phone]
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