I202603 NOPV

•f� Idaho Public Utilities Commission Brad Little,Governor
- P.O.Box 83720,Boise,ID 83720.0074 Edward Lodge,President
~� John R.Hammond,Jr.,Commissioner
Dayn Hardie,Commissioner
April 14, 2026 Report# I202603
Pat Darras—Vice President of Engineering& Operations Services
Intermountain Gas Company
400 N 41h St.
Bismarck, ND 58501
Dear Mr. Pat Darras,
On March 30-31 and April 1, 2026, the Idaho Public Utilities Commission ("Commission"),
Pipeline Safety Division ("Staff'), conducted a field audit of the Boise District of Intermountain
Gas Company ("IGC")pursuant to Chapter 601 of Title 49, United States Code.
Staff observed that some of the Idaho natural gas system(s) owned and operated by IGC
("Company")was out of compliance on item(s). This results in probable violations of the pipeline
safety regulations Title 49, Code of Federal Regulations, Part 192. The probable violations are as
follows:
PROBABLE VIOLATION(S)
1. 49 CFR§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§ 192.703 General
(a) No person may operate a segment of pipeline, unless it is maintained in accordance
with this subpart.
IGC BOISE FIELD AUDIT PROBABLE VIOLATIONS LETTER— Page 1 of 8

49 CFR§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.
(4) Properly installed and protected from dirt, liquids, or other conditions that might
prevent proper operation.
OPS 500 Regulator Inspection and Maintenance
4. REGULATOR INSPECTION AND MAINTENANCE
1.1 Regulators shall be set to lockup at the designated lockup pressure, with some
allowance for lockup fluctuation,but the regulator shall lockup at a pressure equal
to or less than the MAOP.
Findings)
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.
O 312'NW(n 9 43'39'56'N,116'24'49"W t29ft •2579ft
IF' '
Oil -48413-RS-59923 Metal Debris -48413-RS-60048
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2. 49 CFR& 192.1007 What are the required elements of an integrity management plan?
(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 Plan
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 aboveground 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.
IGC BOISE FIELD AUDIT PROBABLE VIOLATIONS LETTER— Page 3 of 8

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 operations and maintenance 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 aboveground 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 right-of-way 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.
IGC BOISE FIELD AUDIT PROBABLE VIOLATIONS LETTER— Page 4 of 8

Findin> (s)•
The following HPSS locations were found with inadequate above-ground markers: 48375-HPSS-
68981, 48375-HPSS-62243, and 48375-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, 2024, HPSS inspections in the Nampa District had 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 aboveground and buried pipeline assets; specifically High-Pressure
Service Sets (HPSS). This pattern of repeated ongoing deficiencies across multiple districts
shows a systemic failure to follow the operator's written procedures, which is an inadequacy of
DIMP requirements.
3. � 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 contact their manager or supervisor as soon
as practical, but no later than the next business day.
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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 it was thawed. The valve crew applied 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
this 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.
4. § 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
I. 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 the protective current applied, and in accordance with sections II and
IV of this appendix.
192.471 External corrosion control: Test leads.
1. Each test lead wire must be connected to the pipeline so as to remain mechanically
secure and electrically conductive.
4. MONITORING PIPELINES UNDER THE INFLUENCE 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. 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.
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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.
F ilidin�4(s):
Regulator Station 48413 RS 59940 had a pipe to soil potential reading of—0.62 mV. That value
was below the—0.85 mV 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.
IGC BOISE FIELD AUDIT PROBABLE VIOLATIONS LETTER— Page 7 of 8

REQUESTED ACTIONS
A reply to this correspondence is required no later than 45 days from the date of this letter. Please
submit a written reply providing a statement of all relevant facts including a complete description
of the corrective action(s) taken with respect to the above referenced probable violations, and all
actions to be taken to prevent future failures in these areas of concern. This written reply must be
signed by a Company official with authority to bind the Company.
Please send all documents to our office at 11331 W. Chinden Blvd, Boise, Idaho 83714-1021. Be
advised that all material you submit in response to this enforcement action may be a public record
and subject to disclosure under Idaho's Public Records Law. See Idaho Code §§74-101 et seq.
If you wish to dispute any of the above referenced potential violations,you have the right to appear
before the Pipeline Safety Division in an informal conference before May 29, 2026, at the above
address. You have the right to present relevant documents and evidence to the Pipeline Safety
Division at that conference. The Pipeline Safety Division will make available to you any evidence
which indicates that you may have violated the law, and you will have the opportunity to rebut this
evidence.See Commission Orders 35095 and 35334,which can be found at https://puc.idaho.gov/.
If you intend to request an informal conference, please contact the Pipeline Safety Division no
later than May 14,2026.
If you wish to dispute any of the allegations in this Notice,but do not want an informal conference,
you may send the Pipeline Safety Division a written reply to this Notice. This written reply must
be filed with the Commission on or before May 29, 2026, and must be signed by a Company
official with authority to bind the Company. The reply must include a complete statement of all
relevant facts, and all documentation, evidence, and argument the Company submits to refute any
of the above referenced probable violations.
These violations may be subject to any Commission enforcement action as allowed under Idaho
law including,but not limited to, potential civil penalties in accordance with 49 CFR 190.223(a).
If you have any questions concerning this Notice,please contact me at(208) 334-0333. All written
responses should be addressed to me at the above address, or you may fax your response to (208)
334-3762.
We appreciate your attention to this matter and your effort to promote pipeline safety.
Sincerely,
Jeff Brooks
Pipeline Safety, Program Manager
Idaho Public Utilities Commission
11331 W.Chinden Blvd.Ste 201-A Boise ID 83714
Telephone:[phone] Facsimile:[phone]
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