I202603 NOPV Response

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 14,2026(Report#I202603)
Dear Mr.Brooks,
This letter is intended to address four(4)notices of probable violation stemming from a field audit conducted by the
Idaho Public Utilities Commission(IPUC)March 30-31 and April 1,2026,of Intermountain Gas Company's(IGC)
Boise 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
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.
49 CFR§ 192.739 Pressure limiting and regulating stations: Insnection and testing.
(a)Each pressure limiting station,relief device(except rupture discs),and pressure regulating station
and its equipment must be subjected to 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.
(4) Properly installed and protected from dirt,liquids,or other conditions that might prevent
proper operation.
Finding(s):
Regulator Station 48413-RS-59923,the primary regulator failed to achieve lock-up due to significant oil
accumulation on the regulator diaphragm.Regulator station 48413-RS-60048,the secondary regulator failed to
achieve lock-up due to metal shavings/debris found on the regulator seat.
0312'N W M 043'3756'N,116-24'49'W t291t•25796
�y l:_�111IIT^I/
C
— 74
i y
Oil-48413-RS-59923 Metal Debris-48413-RS-60048

EXECUTIVE OFFICES
INTERMOUNTAIN GAS COMPANY
555 SOUTH COLE ROAD-P.O.BOX 7608•BOISE,IDAHO 83707•[phone]•FAX:[phone]
intermountain (:as Resnonse
Regulator Station 48413-RS-59923: The regulator was disassembled, cleaned, and reassembled onsite and
subsequently locked up properly.A follow up inspection to check for the presence of oil has been scheduled for June
2026. Oil has not been present at this regulator station during previous inspections.
Regulator Station 48413-RS-60048: The regulator was disassembled, cleaned, and reassembled onsite and
subsequently locked up properly. No previous issues have been identified at this location. The secondary regulator
locked up as expected during the 2025,2024,2023,and 2022 annual inspections.
2. 49 CFR 8 192.1007 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 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.
3.2.4. Other Outside Force Damage
Other outside force damages are a result from fire or explosion,deliberate or willful acts,such as
vandalism and vehicular damage.Only above ground facilities are considered when determining if
this threat is present. The primary concern is areas where gas piping is close enough to vehicular
traffic such as automobiles,trucks,forklifts,snowplows,construction equipment,etc.,where it may
be reasonably expected that damage from vehicle movement could occur.Facilities in locations
known to be subject to vandalism,destruction,wreckage,sabotage,or other harm(e.g.,unauthorized
adjustment or valve movement)may carry the other outside force damage threat.
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.

EXECUTIVE OFFICES
INTERMOUNTAIN GAS COMPANY
555 SOUTH COLE ROAD-P.O.BOX 7608• BOISE,IDAHO 83707•[phone]• FAX:[phone]
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.
49 CFR§ 192,707 Line markers for mains and transmission lines
(c)Pipelines aboveground. Line markers must be placed and maintained along each section of a
main and transmission line that is located above ground in an area accessible to the public.
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.
Finding(
The following HPSS locations were found with inadequate above-ground markers:48375-HPSS-68981,48375-
HPSS-62243,and 48735-HPSS-62332—Require Carsonite markers.
This issue was also identified during multiple other field district audits throughout IGC's system
• August 5-6,2025,HPSS inspections in the Idaho Falls District where multiple HPSS's were found with
inadequate or missing Carsonites.
• March 24-28,2025,HPSS inspections in the Pocatello District where multiple HPSS's were found with
inadequate or missing Carsonites.
• February 28-29,2025,HPSS inspections in the Nampa District where multiple HPSS's were found with
inadequate or missing Carsonites.
Missing and/or inadequate markers for assets directly show the inability of the DIMP program to identify,evaluate
appropriate risk,and implement preventative and mitigative measures for locating and protecting above ground and
buried pipeline assets;specifically High-Pressure Service Sets(HPSS).This pattern of ongoing deficiencies across
multiple districts shows a systemic failure to follow the operator's written procedures,which is an inadequacy of
DIMP requirements.

EXECUTIVE OFFICES
INTERMOUNTAIN GAS COMPANY
555 SOUTH COLE ROAD-P.O.BOX 7608•BOISE,IDAHO 83707•[phone]•FAX:[phone]
intermountain (:as Resnonse
IGC respectfully disputes that pipeline marker deficiencies, as they relate to High Pressure Service Sets (HPSS),
constitute as a probable 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 Program.
IGC DIMP Appendices demonstrate that HPSS assets have been identified,evaluated,and incorporated into DIMP.
Appendix C(Threat Identification) identifies HPSSs as a potential threat category evaluated within DIMP.
HPSSs are included under multiple threat categories, including Outside Force Damage and Equipment
Failure. Appendix C also documents that inspection programs have been completed and that an ongoing
maintenance schedule has been established for these facilities. OPS 304—High Pressure Service Set(HPSS)
and Farm Tap Inspection&Maintenance provides procedures for the inspection of HPSSs and farm taps to
ensure proper and sufficient regulator and overpressure protection of downstream pipelines.
Appendix D (Risk Input) demonstrates incorporation of HPSSs, into the DIMP risk model. This includes
defined weighting factors, differentiated scoring based on installation date, and explicit consideration of
outside-force and vehicular exposure risks.
Accordingly,IGC's DIMP meets the requirements of 49 CFR§192.1007(b){c)as it identifies applicable threats and
evaluates and ranks the risk of those threats.
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. Per 49 CFR §192.707(c), as referenced, above,
"[1]ine markers must be placed and maintained along each section of a main and transmission line that is located above
ground in an area accessible to the public."A high pressure service set(HPSS)is not considered a main or transmission
line.An HPSS is a regulating facility that reduces service line pressures of 61 psig or greater to a pressure of 60 psig
or less (i.e., first stage cut). The regulator at the meter set then reduces the pressures from 60 psig or less to the
applicable delivery pressure(i.e.,second stage cut).
HPSS inspection and maintenance requirements are outlined within OPS 304—High Pressure Service Set(HPSS)and
Farm Tap Inspection &Maintenance. Additionally, HPSSs are included in IGC's atmospheric corrosion survey as
outlined in OPS 403 — Atmospheric Corrosion and Monitoring. OPS 610 —Pipeline Patrolling and Continuing
Surveillance,as referenced above,does not apply to HPSSs.
IGC evaluated the HPSSs identified by the IPUC utilizing the requirements outlined in section 2.13.of OPS 304 and
section 2.15. of OPS 403 as referenced above. 48375-HPSS-68981 at 150 E Hubbard Rd, Kuna is located in a
residential yard.It is not near the right-of-way or in a high traffic area.While the HPSS is visible,due to the condition
of the yard, a pipeline marker was installed. 48375-HPSS-62243 at 1420 W Hubbard Rd and 48375-HPSS-62332 at
1530 W Hubbard Rd,Kuna are both located in well maintained residential yards. The HPSSs are clearly visible and
not near the right of way or in a high traffic area;therefore,do not require pipeline markers.
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

EXECUTIVE OFFICES
INTERMOUNTAIN GAS COMPANY
555 SOUTH COLE ROAD-P.O.BOX 7608• BOISE,IDAHO 83707•[phone]•FAX:[phone]
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
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.
3. 49 CFR § 192.181 Distribution line valves
(a)Each high pressure distribution system must have valves spaced so as to reduce the time to shut
down a section of main in an emergency. The valve spacing is determined by the operating pressure,
the size of the mains,and the local physical conditions.
(b)Each regulator station controlling the flow or pressure of gas in a distribution system must have a
valve installed on the inlet piping at a distance from the regulator station sufficient to permit the
operation of the valve during an emergency that might preclude access to the station.
(c)Each valve on a main installed for operating or emergency purposes must comply with the
following:
(1)The valve must be placed in a readily accessible location so as to facilitate its operation in an
emergency.
(2)The operating stem or mechanism must be readily accessible.
OPS 703 Valve inspection and Maintenance
4.Valves that require maintenance(see Section 3)found inaccessible and/or inoperable must be
remedied.The remediation shall be completed prior to the compliance date for the maintenance.
4.1.Inaccessible and inoperable valves that separate Emergency Shutdown Sections as defined in
OPS 704—Emergency Shutdown Sections,shall have an alternative valve that is accessible and
operable designated in the place of inoperable valves.(Legacy terms for Emergency Shutdown
Sections include Shutdown Areas,E-Valve Districts,Sectionalizing Plans,Key Valves,etc.).If
applicable,the change will be recorded in the district Emergency Shutdown Plans.
4.1.1.Personnel who discover inaccessible and inoperable Emergency Shutdown Section
valves shall notify local Field Operations Management as soon as practicable,but no
later than the next business day.
4.1.2.Local Field Operation Management,or designee,shall submit an ENGMOC to
report
inaccessible and inoperable Emergency Shutdown Section valves as soon as practical,
but no later than the next business day.
Finding(s)•
Valve 48413-VLV-29800 was inoperable until was thawed.The valve crew pressurized water to melt the ice
buildup on the actuator.Once thawed,the valve key was successfully used to operate the valve.If a service
technician,meter technician,or service crew had needed to operate the valve during an emergency, it would not
have operated in that condition. This is the second consecutive year where Boise district valves were unable to
be operated during the field inspection due to ice formation.
Intermountain Gas Response
IGC respectfully disputes that this finding constitutes as a violation of 49 CFR §192.181 or section 4 of OPS 703—
Valve Inspection and Maintenance as referenced above.
Valve 48413-VLV-29800 is located in a readily accessible location and is oriented for easily obtainable access to the
operating mechanism,meeting the installation requirements of 49 CFR§192.181.
As stated in OPS 703:

EXECUTIVE OFFICES
INTERMOUNTAIN GAS COMPANY
555 SOUTH COLE ROAD-P.O.BOX 7608•BOISE,IDAHO 83707•[phone]•FAX:[phone]
4. Valves that require maintenance (see Section 3) found inaccessible and/or inoperable must be remedied.
The remediation shall be completed prior to the compliance date for the maintenance.
4.1.Inaccessible and inoperable valves that separate Emergency Shutdown Sections as defined in OP 704—
Emergency Shutdown Sections, shall have an alternative valve that is accessible and operable designated in
the place of inoperable valves.(Legacy terms for Emergency Shutdown Sections include Shutdown Areas,E-
Valve Districts, Sectionalizing Plans, Key Valves, etc.). If applicable, the change will be recorded in the
district Emergency Shutdown Plans.
As stated in 49 CFR §192.747(b) "Each operator must take prompt remedial action to correct any valve found
inoperable,unless the operator designates an alternative valve."
With prompt remedial action taken onsite by removing the ice and verifying the valve was operable, the designation
of an alternative valve was not required.
Additionally,as required by OPS 703,annual maintenance for 48413-VLV-29800 was conducted in 2025,2024,2023,
and 2022 with no issues identified.
4. 49 CFR 8 192.463 External corrosion control: Cathodic protection.
(a)Each cathodic protection system required by this subpart must provide a level of cathodic
protection that complies with one or more of the applicable criteria contained in Appendix D of this
part.If none of these criteria is applicable,the cathodic protection system must provide a level of
cathodic protection at least equal to that provided by compliance with one or more of these criteria.
Appendix D to Part 192— Criteria for Cathodic Protection and Determination of Measurements
1. Criteria for cathodic protection-
A. Steel,cast iron,and ductile iron structures.
(1)A negative(cathodic)voltage of at least 0.85 volt,with reference to a saturated
copper-copper sulfate half-cell.Determination of this voltage must be made with
protective current applied,and in accordance with sections II and IV of this appendix.
49 CFR S 192,463 External corrosion control: Cathodic protection.
1. Each test lead wire must be connected to the pipeline so as to remain mechanically secure and
electrically conductive.
4.MONTTORTNG PIPELINE UNDER THE. INFIX F,NCF. OF CATHODIC PROTECTION
4.1.Annual cathodic protection survey locations(test points)shall be selected by Corrosion
Control Department personnel and be located at sufficient locations to determine the
adequacy of cathodic protection and electrical isolation.Consider the following areas: dead
ends of steel mains and transmission lines,areas with known corrosion,and areas within the
system which possess the lowest levels of cathodic protection.
4.1.1.Pipe A pipe to soil potential survey shall be conducted annually,not to exceed 15 months
to determine if the following minimum criteria is achieved.
4.1.1.1.A minimum pipe to soil potential shall be equal,or more electronegative
than-0.850 V DC.Voltage(IR)drops other than those across the structure electrolyte boundary shall
be considered for valid interpretation.
4.1.1.1.1. A minimum pipe to soil polarized potential shall be equal,or more electronegative than-
0.850 V DC.Polarized potentials shall be determined by interrupting the protective current source(s)
or through the use of a cathodic protection coupon detailed in NACE TM0497 and NACE SP0104.
Findinu(s):
Regulator Station 48413 RS 59940 has a pipe to soil potential reading of-0.62mV. That value was below the-
0.85mV criteria commonly used to demonstrate adequate cathodic protection with the requirements of 49 CFR
Part 192, Subpart I.Upon identification of the low potential,IGC personnel conducted a follow up inspection to
determine the cause of the inadequate reading and discovered that the test leads inside the Maloney test post
were disconnected.Additionally,multiple Maloney posts throughout the district were assumed to have
disconnects due to locating contractors.

EXECUTIVE OFFICES
INTERMOUNTAIN GAS COMPANY
555 SOUTH COLE ROAD-P.O.BOX 7608•BOISE,IDAHO 83707•[phone]•FAX:[phone]
intermountain (:as Resnonse
As stated above,the low reading was determined to be caused by disconnected test leads inside the Maloney post.The
test leads have since been reconnected.
Training will be provided to personnel who perform line locates on connecting test leads, if needed, after the
completion of a line locate.
Please contact Josh Sanders at(701)222-7773 with questions or comments.
Respectfully Submitted,
�G%��✓G�c-[tiO�L
Pat Darras
Vice President, Engineering& Operations Services
Intermountain Gas Company