20250530Direct Darras.pdf

RECEIVED
May 30, 2025
IDAHO PUBLIC
Preston N. Carter, ISB No. 8462 UTILITIES COMMISSION
Megann E. Meier, ISB No. 11948
GIVENS PURSLEY LLP
601 West Bannock Street
P.O. Box 2720
Boise, Idaho 83701-2720
Office: [phone]
Fax: [phone]
[e-mail]
[e-mail]
Attorneys for Intermountain Gas Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION Case No. INT-G-25-02
OF INTERMOUNTAIN GAS COMPANY
FOR THE AUTHORITY TO INCREASE
ITS RATES AND CHARGES FOR
NATURAL GAS SERVICE IN THE STATE
OF IDAHO
DIRECT TESTIMONY OF PATRICK DARRAS
INTERMOUNTAIN GAS COMPANY
MAY 30,2025

INTRODUCTION
1 Q. Please state your name and business address.
2 A. My name is Patrick C. Darras and my business address is 400 North Fourth Street,
3 Bismarck,North Dakota 58501.
4 Q. By whom are you employed and in what capacity?
5 A. I am employed by Intermountain Gas Company ("Intermountain" or"Company"), a
6 wholly-owned subsidiary of MDU Resources Group, Inc. ("MDU Resources"), as Vice
7 President—Engineering, Operations Services, and Compliance for Intermountain,
8 Montana-Dakota Utilities Co. ("Montana-Dakota"), Great Plains Natural Gas Co. ("Great
9 Plains"), and Cascade Natural Gas Corporation("Cascade"), collectively known as "MDU
10 Utilities Group".
STATEMENT OF QUALIFICATIONS
1 1 Q. Please outline your educational and professional background.
12 A. I am a graduate of North Dakota State University with a Bachelor of Science Degree in
13 Construction Engineering. I also hold an MBA along with a Master's Degree in
14 Management, both from the University of Mary in Bismark,North Dakota. In June of
15 2014, I attended the Utility Executive Course at the University of Idaho in Moscow, Idaho.
16 I began my career in 2002 as a gas engineer with Montana-Dakota in Bismarck,
17 North Dakota. I held that position for four years primarily working with the construction
18 and service group in day-to-day operations. In 2006, I was promoted to the role of Region
19 Gas Superintendent where I was responsible for the overall gas engineering, construction,
20 and service of the Dakota Heartland Region of Montana-Dakota. I worked in that capacity
21 for two years and was then promoted to Region Director for Montana-Dakota's Dakota
PAGE 1 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Heartland Region and Great Plains. My responsibility in this role was oversight of all gas
2 and electric operations for the Region. In January 2015, I was promoted to Vice President
3 of Operations for Montana-Dakota and Great Plains. My responsibilities in this role
4 included gas and electric distribution operations and engineering across the five states of
5 North Dakota, South Dakota, Montana, Wyoming, and Minnesota. In June of 2018, I
6 accepted the role of Vice President—Engineering and Operations Services and in January
7 of 2025 accepted my current role as Vice President—Engineering, Operations Services,
8 and Compliance.
9 Prior to joining Montana-Dakota, I worked for a local industrial contractor
10 specializing in refinery and power plant maintenance along with turn-key construction of
I I industrial facilities such as refineries and food processing plants. I spent seven years with
12 this group in various capacities in engineering, construction, and project management.
13 Q. Please describe your duties and responsibilities with Intermountain.
14 A. I have executive responsibility for the development, coordination, and implementation of
15 Intermountain's strategies and policies relative to areas of engineering and operations
16 including design, construction, compliance, and pipeline integrity and safety.
PURPOSE OF TESTIMONY
17 Q. Please summarize your testimony.
18 A. The purpose of my testimony is to: 1) discuss the Company's efforts to improve the safety
19 and reliability of its natural gas distribution and transmission system through public
20 awareness and damage prevention; 2)provide an overview of the Company's project
21 selection and budgeting process; 3)provide an overview of the Company's major capital
PAGE 2 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I projects that have been completed since the last rate case; and 4)provide an overview of
2 the major 2025 Pro Forma capital projects.
3 Q. Are you sponsoring any exhibits to your direct testimony?
4 A. No.
PUBLIC AWARENESS AND DAMAGE PREVENTION
5 Q. Please describe the Company's Public Awareness and Damage Prevention efforts and
6 related recommended practices.
7 A. Public Awareness: Intermountain follows the American Petroleum Institute Recommended
8 Practice (API RP) 1162 which is incorporated by reference into federal regulations.I API
9 RP 1162 is an industry consensus standard that provides guidance and recommendations to
10 pipeline operators for development and implementation of enhanced public awareness
11 programs. Intermountain's public awareness activities include educating the public,
12 appropriate government organizations, and persons engaged in excavation activities on the
13 following: (1)use of the Digline one-call system prior to excavation; (2)possible hazards
14 associated with unintended releases from a gas pipeline facility; (3)physical indications
15 that such a release may have occurred; (4) steps that should be taken for public safety in
16 the event of a gas pipeline release; and(5)procedures for reporting such an event.
17 Damage Prevention: The Company engages in location of gas facilities prior to
18 excavation work(when notified by the excavator)through its contractual relationship with
19 Digline. Excavators can call Digline at no charge to the excavator. Digline then contacts a
20 Company representative who locates Intermountain gas facilities within 48 hours of the
I See 49 C.F.R. 192.616(a).
PAGE 3 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I request. Additionally, Company representatives regularly meet with excavators to educate
2 them about the importance of safe excavation.
3 Q. How does the Company's one-call notification process work in Idaho?
4 A. An excavator, prior to conducting an excavation in the State of Idaho, must typically notify
5 the underground facility owner by way of a one-call service. For the Company, which
6 owns underground natural gas facilities, the one-call service is provided by its contractor,
7 Digline. With few exceptions, the excavator must call the one-call notification center
8 (Digline) at least two business days, but not more than ten business days before the
9 scheduled date of excavation.
10 Upon receipt of the excavation notice, the underground utility owner or its agent
11 must locate and mark facilities in the proximity of the proposed excavation location with
12 "reasonable accuracy." Intermountain employees or a contracted locator perform locating,
13 as required by law, within two business days after the receipt of an excavation notification.
14 Q. How important is the one-call notification process for the enhancement of stakeholder
15 and community safety related to underground facilities?
16 A. In the Company's experience, the one-call notification process and its valuable
17 relationships with excavating contractors and internal locators are vital to meeting and
18 enhancing its important obligations to community and stakeholder safety around its natural
19 gas facilities.
20 The role of Digline is vital because they are the first point of contact with the
21 excavator and gather important information related to the excavation in question. Utilizing
22 database software, which cross-references the territory with GPS coordinates and street-
23 level information from Idaho's county assessors, the one-call service provides a high
PAGE 4 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I degree of accuracy with each locate request. In addition, the one-call service notifies all
2 facility owners within a proposed excavation area, who in turn perform their own facility
3 locates within the time period specified by state law. This allows for coordination of
4 relevant stakeholders and is what makes the service so valuable to the Company's
5 objective to ensure and enhance customer safety.
6 Q. Is there a cost associated with the Company's use of Digline?
7 A. Yes. While one-call notification services are provided free of charge to both contractors
8 and the general public, the Company does incur a nominal fee for every one-call locate
9 requested. In the Company's case, Digline charges the Company $1.75 per one-call locate
10 ticket transaction.
11 Q. Can the Company's costs associated with Digline vary over time?
12 A. Yes, as mentioned, Digline currently charges Intermountain $1.75 per one-call locate ticket
13 transaction. As the volume of locate tickets requested increases or decreases, the cost to the
14 Company correspondingly fluctuates. For example, between 2022 and 2024 the number of
15 locates requested in the Company's service territory increased from approximately 128,243
16 to 148,268. This increase in requested locates corresponds with the increase in costs for
17 this service. The drivers behind the number of locates may be related to regional economic
18 factors such as the expansion or contraction of the construction industry, for example,
19 which would cause the one-call charges to increase or decrease accordingly.
PAGE 5 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Q. Does the investment in the Company's Public Awareness and Damage Prevention
2 programs and one-call and locating practices save facility damage costs and enhance
3 public safety over time?
4 A. Yes. The Company believes its investment in public awareness and damage prevention
5 activities, in coordination with its one-call and locating staff and contractors, has been an
6 important factor in reducing the overall rate of damages per 1,000 incidents in the
7 Company's service territory. For example, in 2022, the rate of damages per 1,000 was
8 6.36. And in 2024, that rate declined to 4.89. This reduction occurred despite the increase
9 in the number of locate requests. Additionally, the Company maintains a policy of billing
10 at-fault contractors for damages, including the labor and material costs of repairing the
11 Company's underground facility after a negligent excavation practice occurs.
12 Q. Does the Company utilize marketing& outreach efforts?
13 A. Yes, Intermountain utilizes a third party, the Public Awareness Pipeline Association
14 ("PAPA"), for stakeholder outreach required per API RP 1162. This outreach includes
15 specific information and Digline education for emergency responders,public officials,
16 excavators, and the general public. Intermountain supplements the API RP 1162
17 requirements and use of PAPA with targeted online banner ads, radio ads, mailers,
18 community events, and training classes. Intermountain also contracts with Culver to
19 provide educational marketing to schools in the Company's service territory. The goal of
20 these additional forms of outreach is to relay the Digline message and encourage all
21 stakeholder groups to utilize the one-call system. Each form of outreach/marketing is
22 tracked to measure message success, along with the use of pulse surveying to determine
23 the effectiveness of the messaging.
PAGE 6 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

OVERVIEW OF PROJECT SELECTION AND BUDGETING PROCESS
1 Q. What types of major capital projects are included in this testimony?
2 A. Most of the major capital projects discussed in this direct testimony are pipeline
3 replacement projects that have been identified for safety reasons and to reduce risk on
4 Intermountain's system, or system reinforcements or system expansions that have been
5 identified as needed to ensure system reliability and to accommodate growth on the
6 Company's system. A reinforcement is an upgrade to existing infrastructure or new system
7 additions, which increases system capacity, reliability, and safety. An expansion is a new
8 system addition to accommodate an increase in demand. Collectively,these are known as
9 distribution enhancements. Distribution enhancements do not reduce demand, nor do they
10 create additional natural gas supply. Instead, enhancements can increase the overall
11 capacity of a distribution pipeline system while utilizing existing gate station supply
12 points. The two broad categories of distribution enhancement solutions are pipelines and
13 regulators.
14 Q. Please provide an overview of Intermountain's identification and selection process for
15 distribution enhancement projects.
16 A. Intermountain's planning process for distribution enhancement projects relies on district-
17 level information, the Company's Integrated Resource Plan("IRP"), and demand studies.
18 At a district-level, Intermountain's engineering department works closely with the
19 Company's energy services representatives and district managers to meet existing and
20 anticipated future needs while ensuring the system is safe and reliable. As towns develop
21 and add new homes and businesses, the need for pipeline expansions and reinforcements
22 increases. The system expansion projects are historically driven by new city developments
PAGE 7 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I or new housing plats. Before distribution enhancements can be constructed to serve these
2 new customers, engineering analysis is performed. Using system modeling software to
3 represent cold weather conditions,predictions can be made about the capacity of the
4 system. As new groups of customers seek natural gas service, the models provide options
5 on how best to serve them reliably.
6 The IRP is a critical planning tool for identifying needed projects, conducting
7 alternatives analysis, and selecting distribution enhancement projects. System planning
8 involves gate station capacity analysis and forecasting. Over time, each gate station will
9 take on more and more demand and it is Intermountain's goal to stay ahead of potential
10 reliability issues by predicting and identifying constraints on its system. The IRP growth
11 data, along with design day modeling (discussed below), allows Intermountain to forecast
12 necessary gate station upgrades. SCADA technology utilized by Intermountain allows
13 verification of numbers with real time and historic gate station flow and pressure data.
14 Demand studies facilitate modeling multiple demand forecasting scenarios, identifying
15 constraints, and optimizing corresponding combinations of pipe modification and pressure
16 modification solutions to maintain adequate pressures throughout the network. After
17 developing a working demand study, the Company analyzes every system at design day
18 conditions to identify areas where potential outages may occur. Within a given area,
19 projects/reinforcements are selected using the following criteria:
20 • The shortest segment(s) of pipe that improves the deficient part of the distribution
21 system.
22 • The segment of pipe with the most favorable construction conditions, such as ease
23 of access or rights, fewer traffic issues, and minimal to no water, railroad, major
24 highway crossings, etc.
PAGE 8 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

1 • The segment of pipe that minimizes environmental concerns including minimal to
2 no wetland involvement, and the minimization of impacts to local communities
3 and neighborhoods.
4 • Total construction costs including restoration.
5 Once a project/reinforcement is identified, the design engineer or energy services
6 representative begins a more thorough investigation by surveying the route and filing for
7 permits. This process may uncover additional impacts, such as moratoriums on road
8 excavation, underground hazards, discontent among landowners, etc., resulting in another
9 iteration of review of the above project/reinforcement selection criteria. Figure 1, below,
10 provides a schematic representation of the distribution project process flow.
PAGE 9 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

l Figure 1.Distribution Planning Project Process Flowchart
nfo:
Design Day
-City Developments
Models
-New Housing Plats
►f
System Limitation
Computer Model Pressure
Concerns
BENEFI
FEASIBILITY
ID Potential Projects and
Enhancement Types
(Individually)
COST ad 0
BENEFIT Rank Projects Based On
10. Priority
FEASIBIL '
COST
Schedule Into Budget
2 J
PAGE 10 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Q. Does the Company also consider demand side management alternatives?
2 A. Yes. The Company also reviews the impacts of proposed conservation resources on
3 anticipated distribution constraints through its IRP process. While Intermountain attempts
4 to influence these decisions through its conservation programs, the consumer is still the
5 ultimate decision maker regarding the purchase and use of a conservation measure.
6 Therefore, in the short term, Intermountain does not anticipate that the peak day load
7 reductions resulting from incremental conservation will be adequate to eliminate
8 distribution system constraint areas at this time.
9 Q. How does the Company's Integrated Resource Planning process inform project
10 selection?
11 A. Intermountain's IRP evaluates safe, economical, and reliable full-path delivery of natural
12 gas from basin to the customer meter. Securing adequate natural gas supply and sufficient
13 pipeline transportation capacity to Intermountain's city gate stations are necessary
14 elements for providing gas to the customer. The other essential element is ensuring the
15 distribution system growth behind the city gate stations is not constrained. Important parts
16 of the distribution planning process include forecasting local demand growth, determining
17 potential distribution system constraints, analyzing possible solutions, alternative analysis,
18 and estimating costs for distribution system enhancements.
19 Analyzing resource needs in the IRP ensures adequate upstream capacity is
20 available to the city gate stations, especially during a peak event. Distribution planning
21 focuses on determining if adequate pressure will be available during a peak hour. Given
22 this nuance, distribution planning addresses many of the same goals, objectives, risks, and
23 solutions as resource planning.
PAGE 11 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Q. Are all the major projects identified in the Company's IRP?
2 A. No. Safety-related projects are not typically included in the IRP since safety-related
3 projects are required by Federal and State Pipeline Safety regulations and are required to
4 ensure the Company is operating its gas system safely. Generally, the projects that are
5 included in the IRP are distribution enhancement projects, which address system capacity,
6 maintenance, and growth.
7 Q. How does the Company identify safety-related projects?
8 A. The Company utilizes input from its system engineers, Field Operations employees, and
9 other subject matter experts who have intimate knowledge of specific portions of the
10 Company's system. These experts identify areas of potential concern and identify areas of
11 risk to develop the safety-related projects to remediate risk.
12 The Company also use its Distribution Integrity Management Program ("DIMP")
13 and Transmission Integrity Management Programs ("TIMP")to identify risks on the
14 system,by utilizing system knowledge based on known distribution systems
15 characteristics, historical maintenance information, available outside source information,
16 and the use of subject matter experts who are knowledgeable in operation, maintenance,
17 design and construction. A risk model is used to evaluate and manage the risk, assigning
18 appropriate likelihood and consequence factors based on the known system information
19 and potential threats to the company's system. The risk model is used to identify, assess,
20 and prioritize integrity risks. The Company reviews and analyzes risk model outputs after
21 each model run to identify areas of highest risk and those areas where risk increased from
22 the last model run.
PAGE 12 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I The Company also considers and analyzes existing and proposed measures to
2 address risks to the Company's system. The prioritization and selection of the appropriate
3 remediation actions depends on the type of risk being addressed, whether the risk is current
4 or potential, and the viability of the remedial action in managing the relevant risk factors.
5 Q. What types of projects are typically performed to address safety-related concerns?
6 A. Pipeline replacement is typically the most viable option to remediate risks associated with
7 corrosion, natural forces, material, weld,joint, and/or equipment. If Intermountain
8 determines that replacement is an appropriate action to reduce the risk, the Company
9 establishes a replacement project.
10 Q. How does the Company prioritize and select safety-related projects?
11 A. Once a safety-related project has been identified, the Company plans and prioritizes the
12 project to ensure that higher risk threats are mitigated in a timely manner.
13 Q. Please explain the capital projects included in this case.
14 A. Capital projects addressed in this prefiled direct testimony fall into two categories:
15 1) Specific or 2) Programmatic. Specific projects are clearly defined, identifiable, or
16 discrete investments. Programmatic projects are made according to a schedule,plan, or
17 method and are generally investments that are necessary to provide safe, reliable service to
18 Idaho customers.
19 Intermountain's capital project budgeting process is explained in the direct
20 testimony of Lori Blattner. Each of the projects and programs discussed in this direct
21 testimony have been approved by Intermountain management in accordance with that
22 process and Intermountain's Approval Authorization Policy, which is provided as an
23 Exhibit to Lori Blattner's direct testimony.
PAGE 13 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I My prefiled direct testimony will first discuss specific projects with actual costs
2 over one million dollars that have been placed in service since the Company's last test
3 year. A complete list of the 2023 through 2024 projects is included as an Exhibit to the
4 direct testimony of Lori Blattner. The next section will address specific and programmatic
5 projects with actual or estimated costs over one million dollars that will be placed in
6 service in Intermountain's 2025 Pro Forma period. Finally, my testimony will address
7 specific and programmatic projects with actual or estimated costs over two hundred
8 thousand dollars, but under one million dollars, that will be placed in service in
9 Intermountain's 2025 Pro Forma period. A complete list of Pro Forma projects is included
10 as an Exhibit to the direct testimony of Lori Blattner.
11 Table 1 below illustrates the requested plant additions included in my testimony.
Table 1 -Additions to Plant In-Service
Description Specific Programmatic Total
Projects Projects
2023 -2024 Major Projects over$1M
Testimony of Patrick C Darras $ 43,285,106 $ 28,691,913 $ 71,977,018
2025 Major Projects over$1M
Testimony of Patrick C Darras $ 31,925,725 $ 13,251,580 $ 45,177,305
2025 Major Projects over$200K
Testimony of Patrick C Darras $ 10,662,516 $ 3,422,267 $ 14,084,783
12
PAGE 14 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

MAJOR PROJECT ADDITIONS TO PLANT IN SERVICE 2023—2024.
1 FP-101001 - Gas Meters-Total Company IGC
2 Q. Please describe FP-101001 —Gas Meters Total Company IGC.
3 A. The costs in this Funding Project ("FP") are for new meter purchases to measure customer
4 gas usage.
5 Q. Why did the Company undertake the project?
6 A. This FP is necessary because meters help to ensure customers are billed accurately.
7 Q. How will customers benefit from the project?
8 A. The customer benefit of this project is that meters help to ensure customers are billed
9 accurately.
10 Q. Did the Company consider alternative ways to meet the need for the project?
11 A. No, because meters are the only way to accurately bill customers and therefore, they are
12 required.
13 Q. When was the project placed in service?
14 A. This is a programmatic funding project that will never close. Meters are purchased as
15 needed for new services and existing meter replacements throughout the year, closing to
16 plant in service each month.
17 Q. What were the total costs for the project?
18 A. Total costs closed to plant in 2023 and 2024 were $9,667,562 and$10,118,132,
19 respectively.
PAGE 15 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I FP-101003 - Gas Regulators-Total Company IGC
2 Q. Please describe FP-101003 - Gas Regulators-Total Company IGC.
3 A. The costs in this FP are for new regulator purchases to regulate pressure and provide
4 overpressure protection at the customer's premise.
5 Q. Why did the Company undertake the project?
6 A. Regulators provide safe delivery pressure and overpressure protection at the customer's
7 premise. Regulators also provide accurate pressure to calculate the pressure factor correctly
8 for customer billing.
9 Q. How will customers benefit from the project?
10 A. Customers will receive gas at safe pressures and they will receive accurate billing.
11 Q. Did the Company consider alternative ways to meet the need for the project?
12 A. No, because regulators are needed to meet CFR 192 federal code requirements.
13 Q. When was the project placed in service?
14 A. This is a programmatic funding project that will never close. Regulators are purchased and
15 placed in service as needed for new services and existing regulator replacements
16 throughout the year.
17 Q. What were the total costs for the project?
18 A. Total costs closed to plant in-service for the years 2023 and 2024 are $583,076 and
19 $696,230, respectively.
20 FP-318180, FP-318181 - System Safety and Integrity Program -Pipe Replacement Program
21 Q. Please describe the System Safety and Integrity Program.
22 A. The System Safety and Integrity Program("SSIP") is a structured pipe replacement
23 program for replacing early vintage plastic pipe and early vintage steel pipe. Early vintage
PAGE 16 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I plastic pipe includes plastic mains, service lines, and associated fittings installed earlier
2 than January 1, 1995. Early vintage plastic pipe is further divided into Pre-1983 and Post-
3 1982. Pre-1983 includes pipe installed prior to January 1, 1983 that may be susceptible to
4 possible low ductile inner wall characteristics that can result in slow crack growth and slit
5 failures, as documented by the Pipeline and Hazardous Materials Safety Administration
6 ("PHMSA"), PHMSA-2004-19856.2 Post-1982 includes pipe installed between January
7 1, 1983 and December 31, 1994 and are classified as early vintage plastic pipe to account
8 for different inventory levels and rates of new material adoption throughout
9 Intermountain's operating locations.
10 Early vintage steel pipe includes steel mains, service lines, and associated fittings
11 installed earlier than January 1, 1970. This pipe presents an increased risk of failure due to
12 external corrosion, material failure, weld or joint failure, and equipment failure.
13 Q. Why did the Company start the SSIP?
14 A. SSIP is a direct result of the PHMSA requirement for operators to implement a DIMP that
15 demonstrates an understanding of the distribution system design and material
16 characteristics; describes the operating conditions and environment; provides the
17 maintenance and operating history; identifies existing and potential threats; evaluates and
18 rank risks; identifies and implements measures to address risks; measures program
19 performance; monitors results; evaluates effectiveness; and periodically assesses and
20 improves the plan. As a result of DIMP, SSIP is a program that identifies and implements
21 measures to address risks to Intermountain's distribution system, by replacing elevated risk
2 Available at https://www.federalregister.gov/documents/2007/09/06/07-4309/pipeline-safety-updated-notification-
of-the-susceptibility-to-premature-brittle-like-cracking-of.
PAGE 17 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I pipe to mitigate identified threats. DIMP requirements are outlined in 49 CFR Part 192
2 Subpart P - Gas Distribution Pipeline Integrity Management.
3 Q. How does the Company prioritize and select safety-related projects as part of its
4 SSIP?
5 A. Intermountain utilizes DIMP and SSIP to identify, analyze and monitor risks related to
6 Intermountain's distribution system, and to create replacement programs that will reduce
7 risk. The SSIP utilizes the DIMP risk model and relative risk score to establish a weighted
8 average risk score for each town within Idaho. The weighted average risk score is then
9 used to identify towns with increased risk related to early vintage plastic pipe and early
10 vintage steel pipe. Ongoing analysis of early vintage plastic pipe and early vintage steel
11 pipe continues to show that this pipe has a greater likelihood to leak and/or have
12 substandard pipe conditions (corrosion, welds/joints, materials, equipment). These
13 segments of main and service lines have an elevated risk of failure as validated by DIMP
14 risk analysis and are, therefore,prioritized for replacement.
15 Q. Why did the Company undertake the project?
16 A. Pipeline replacement is typically the most viable option to remediate risks associated with
17 corrosion, material failure, weld/joint failure, equipment failure, and missing data threats.
18 The SSIP program addresses safety, reliability, and operational risks by replacing pipe
19 systematically, where Intermountain has determined that replacement is an appropriate
20 action to reduce risk.
21 Q. How will customers benefit from the project?
22 A. SSIP replaces and eliminates early vintage plastic pipe and early vintage steel pipe prone to
23 corrosion, material failure, weld/joint failure, equipment failure, and missing data threats.
PAGE 18 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I The replacement of these high-risk systems increases overall public safety and improves
2 system reliability for customers.
3 Q. Did the Company consider alternative ways to meet the need for the project?
4 A. Yes, but as noted, systematic pipe replacement is typically the most viable option for early
5 vintage plastic and steel pipe and, when feasible, Intermountain will still work jointly with
6 State, City, County, or general contractors performing highway, road, and underground
7 infrastructure replacement projects within the same vicinity. This collaboration eliminates
8 duplication of work,provides cost savings, and limits long-term interruptions to
9 Intermountain's customers.
10 Q. Would you please describe the SSIP pipe replacement projects that were completed
11 in 2023 and 2024?
12 A. Yes, Intermountain completed SSIP pipe replacement projects in Parker, Idaho and Boise,
13 Idaho in 2023 and Boise, Idaho in 2024.
14 Q. Would you please describe the Parker SSIP pipe replacement project?
15 A. The Parker SSIP pipe replacement project was a single year project in 2023,primarily
16 focusing on the replacement of Pre-1983 early vintage plastic main and service lines with
17 medium density polyethylene ("MDPE")pipe.
18 Q. Why did the Company undertake the Parker SSIP pipe replacement project?
19 A. Parker was identified in 2023 as Intermountain's highest risk town with early vintage
20 plastic pipe and early vintage steel pipe in the state of Idaho, by Intermountain's SSIP.
21 Q. What was the project timeline for Parker SSIP pipe replacement project?
22 A. The Parker SSIP pipe replacement project was a single year project in 2023.
PAGE 19 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Q. When was the Parker SSIP pipe replacement project placed in service?
2 A. Segments of the Parker SSIP pipe replacement project were placed in service throughout
3 2023and the entire project was completed before the end of 2023.
4 Q. Would you please describe the Boise SSIP pipe replacement project?
5 A. The Boise SSIP pipe replacement project is a multi-year project primarily focusing on the
6 replacement of Pre-1983 early vintage plastic main and service lines with MDPE pipe.
7 Q. Why did the Company undertake the Boise SSIP pipe replacement project?
8 A. Boise was identified in 2023 as Intermountain's 2nd highest risk town with early vintage
9 steel pipe and early vintage plastic pipe in the state of Idaho, by Intermountain's SSIP.
10 With the Parker SSIP pipe replacement being completed in 2023, Bosie became the next
11 highest risk town for replacement.
12 Q. What is the project timeline for Boise SSIP pipe replacement project?
13 A. The Boise SSIP pipe replacement project started in 2023 and will continue through 2027.
14 Q. When was the Bosie SSIP pipe replacement project placed in service?
15 A. Segments of the Boise SSIP pipe replacement project were placed in service throughout
16 2023 and 2024. The 2023 and 2024 phases of the Boise SSIP pipe replacement project
17 were completed before the end of 2023 and 2024, respectively.
18 Q. What were the total costs for the project?
19 A. The total closed to plant in-service for the SSIP Main and Service Replacement project
20 was $3,653,613 for 2023 and$2,166,466 for 2024.
PAGE 20 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Q. Please describe any significant project changes between what was described in the
2 IRP and how it's being described in this testimony.
3 A. There are no significant changes between the information reported in the IRP and in this
4 testimony. SSIP is described in the Infrastructure Replacement section of the IRP.
5 FP-318191 -Fixed Network Equipment-IGC
6 Q. Please describe the Fixed Network Project-IGC.
7 A. From 2016 to 2019 the Company installed metering equipment at each gas meter, capable
8 of electronically capturing and transmitting data, which are called Encoder Receiver
9 Transmitters ("ERT"s). The Fixed Network("FN") is constructed with collectors and
10 repeaters, which are devices that relay the data from the ERTs via 900 MHz radio signals
I I and transmit these data over cellular connections back to the Company's FN servers. The
12 individual data is then compiled into a data management system("DMS") so business
13 applications and software programs can analyze the data. For the fixed network to gather
14 the needed data, the devices must be placed in proximity to the gas meters' ERTs and at a
15 height of at least 20 feet above ground. These devices are typically placed on existing
16 utility poles owned by local power utility providers or existing communication towers
17 owned by local entities or utilities.
18 Q. Why did the Company undertake the project?
19 A. The Company ran a business case and determined that developing a fixed network would
20 provide a more durable, long-term solution for collecting data and would also provide
21 operational benefits and costs savings, including reduced costs associated with meter
22 reading.
PAGE 21 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Q. How will customers benefit from the project?
2 A. This project provides operational benefits and costs savings, including reduced costs
3 associated with meter reading.
4 Q. Did the Company consider alternative ways to meet the need for the project?
5 A. The alternative that was considered was to continue utilizing the current process for
6 reading meters using the mobile system. This alternative was viable,but the business case
7 for moving to a fixed network would not be achievable by staying with the current process.
8 Q. When was the project placed in service?
9 A. FP-318191 is a programmatic funding project placed in service monthly through the
10 duration of years 2023 and 2024.
11 Q. What were the total costs for the project?
12 A. Total costs closed to plant in-service for the years 2023 and 2024 are $1,641,785 and
13 $165,049, respectively.
14 FP-318758 - Rf-Nampa-4.lmi 12"S Ustick Rd Ph. 3
15 Q. Please describe FP-318758 -Rf-Nampa-4.lmi 12"S Ustick Rd Ph. 3
16 A. The 12 inch Ustick Phase 3 project connects an existing high pressure pipeline system to
17 the previously installed phases 1 and 2 of the total Ustick 12 inch plan. This is the final
18 phase of the total plan that extends the 500 psig maximum allowable operating pressure
19 ("MAOP") system from the Nampa Gate Station and Star Road into South Caldwell.
20 Q. Why did the Company undertake the project?
21 A. The new 12 inch pipeline is required to serve new core customer growth in the Canyon
22 County area of interest. The 12 inch pipeline allows for increased operating pressure and
23 higher flow delivered from the Nampa Gate Station.
PAGE 22 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Q. How will customers benefit from the project?
2 A. This project will allow for existing customers to continually receive reliable service while
3 also allowing for future core customer growth and demand.
4 Q. Did the Company consider alternative ways to meet the need for the project?
5 A. Three alternatives were considered to meet the need for this capacity enhancement. These
6 alternatives include Ustick Phase III, Ustick Uprate and an 8-inch High Pressure Extension
7 north of Ustick as discussed in the IRP. Ustick Phase III,which this project is a component
8 of, was chosen in 2021 as the largest capacity increasing alternative.
9 Q. When was the project placed in service?
10 A. FP-318758 was placed in service in December of 2024.
11 Q. What were the total costs for the project?
12 A. Total costs closed to plant in 2024 are $11,379,688.
13 Q. Please describe any significant project changes between what was described in the
14 IRP and how it's being described in this testimony.
15 A. There are no significant changes between the information reported in the IRP and in this
16 testimony.
17 FP-319069 - RF; SV LAT COMPRESSOR
18 Q. Please describe FP-319069 -RF; SV LAT COMPRESSOR
19 A. This project is for the installation of a new compressor station on the Sun Valley lateral,
20 located north of Shoshone, Idaho. This FP covered all project costs, for example, the inlet
21 and outlet main for the compressor,purchase and installation of the compressor unit, and
22 the purchase and construction of the compressor building.
PAGE 23 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Q. Why did the Company undertake the project?
2 A. Growth forecasting on the Sun Valley lateral showed that Intermountain would be unable
3 to reliably serve customers, on a peak degree day, without a major reinforcement to the
4 system.
5 Q. How will customers benefit from the project?
6 A. Customers will benefit from increased reliability on peak degree days as well as increased
7 capacity on the Sun Valley Lateral for additional future customers.
8 Q. Did the Company consider alternative ways to meet the need for the project?
9 A. Yes, a large loop/reinforcement of the Sun Valley Lateral was considered. However, cost
10 benefit analysis pointed to a new compressor station being the better reinforcement option
11 because the station provides additional capacity per project dollar than a
12 reinforcement/loop would.
13 Q. When was the project placed in service?
14 A. The majority of FP-319069 was placed in service in December 2023, the point at which it
15 was in use and useful. In 2024, additional costs related to, and in the scope of the original
16 project, were incurred and closed to plant as stated below.
17 Q. What were the total costs for the project?
18 A. Total costs closed to plant in 2023 and 2024 are $7,824,717 and$380,511, respectively.
19 Q. Please describe any significant project changes between what was described in the
20 IRP and how it's being described in this testimony.
21 A. There are no significant changes between the information reported in the IRP and in this
22 testimony.
PAGE 24 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

1 FP-320646 - GR-BOI-12S SOUTH BOISE HP LOOP
2 Q. Please describe FP-320646: 12" South Boise Loop
3 A. The 12 inch South Boise high pressure ("HP") loop connects a newly installed Northwest
4 Pipeline ("NWT")tap and Kuna Gate Station,providing high pressure and flow
5 capabilities, through the new 12 inch South Boise pipeline into the newly installed
6 regulator station and into the previously installed phases I and 2 of the 8 inch Cloverdale
7 pipeline.
8 Q. Why did the Company undertake the project?
9 A. The new 12 inch pipeline is required to serve new core customer growth in the Central Ada
10 County area of interest. The 12 inch pipeline is a significant part of the entire plan in
I I Central Ada Couty that extends the 500 psig MAOP system from the new Kuna gate
12 station into the existing high pressure systems and eventually allows for a 500 psig loop
13 with State Street and the Nampa Gate Station.
14 Q. How will customers benefit from the project?
15 A. This project will allow for existing customers to continually receive reliable service while
16 also allowing for future core customer growth and demand.
17 Q. Did the Company consider alternative ways to meet the need for the project?
18 A. Yes, the Company considered two alternatives to this project including an uprate of the
19 existing pipeline and the installation of a new pipeline along an alternative route.
20 Q. When was the project placed in service?
21 A. FP-320646 was placed in service in March 2023, the point at which it was in use and
22 useful. In 2024, a cost true up related to, and in the scope of the original project, was
23 closed to plant as stated below.
PAGE 25 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Q. What were the total costs for the project?
2 A. Total costs closed to plant in 2023 and 2024 are $12,365,432 and-$569,309, respectively.
3 Q. Please describe any significant project changes between what was described in the
4 IRP and how it's being described in this testimony.
5 A. There are no significant changes between the information reported in the IRP and in this
6 testimony.
7 FP-321625 - CONST KUNA GATE-MERIDAN-NWP FAC
8 Q. Please describe FP-321625.
9 A. FP-321625 is required as part of the new Kuna Gate Station; this FP is specifically for
10 work required by NWP, the interstate transmission pipeline company that transports
11 Intermountain's natural gas from supply locations to the state of Idaho. NWP installed
12 new facilities to accommodate Intermountain's Kuna Gate upgrade related to FP-321626.
13 Q. Why did the Company undertake the project?
14 A. The new gate station is required to serve the new 12 inch Cloverdale pipeline with
15 adequate pressure and flow capabilities. The 12 inch Cloverdale pipeline was required to
16 serve core customer growth in the Central Ada County area of interest.
17 Q. How will customers benefit from the project?
18 A. The Kuna Gate Upgrade provides increased capacity for core customer growth, as
19 determined by customer growth and usage estimates in the IRP.
20 Q. Did the Company consider alternative ways to meet the need for the project?
21 A. Three alternatives were considered to meet the need for this capacity enhancement. These
22 alternatives include the 12-inch South Boise Loop, uprating the 10-inch HP on Meridian
23 Road and Victory Road or installing a compressor station. The 12-inch South Boise Loop,
PAGE 26 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I which this project is a component of, was chosen in 2021 as the lowest cost option with the
2 most capacity gained.
3 Q. When was the project placed in service?
4 A. FP-321625 was placed in service December 2023.
5 Q. What were the total costs for the project?
6 A. Total costs closed to plant in 2023 are $4,902,384.
7 Q. Please describe any significant project changes between what was described in the
8 IRP and how it's being described in this testimony.
9 A. There are no significant changes between the information reported in the IRP and in this
10 testimony.
11 FP-321626-RF-KUNA-GT-R-KUNA GATE RS
12 Q. Please describe FP-321626.
13 A. FP-321626, Kuna Gate Upgrade project, replaces an existing gate station with larger
14 equipment relocated to a new facility location.
15 Q. Why did the Company undertake the project?
16 A. The new gate station is required to serve the new 12 inch Cloverdale pipeline with
17 adequate pressure and flow capabilities. The 12 inch Cloverdale pipeline was required to
18 serve core customer growth in the Central Ada County area of interest.
19 Q. How will customers benefit from the project?
20 A. The Kuna Gate Upgrade provides increased capacity for core customer growth, as
21 determined by customer growth and usage estimates in the IRP.
22 Q. Did the Company consider alternative ways to meet the need for the project?
23 A. Three alternatives were considered to meet the need for this capacity enhancement. These
PAGE 27 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I alternatives include the 12-inch South Boise Loop, uprating the 10-inch HP on Meridian
2 Road and Victory Road or installing a compressor station. The 12-inch South Boise Loop,
3 which this project is a component of, was chosen in 2021 as the lowest cost option with the
4 most capacity gained.
5 Q. When was the project placed in service?
6 A. FP-321626 was placed in service in December of 2023, the point at which it was in use and
7 useful. In 2024, additional costs related to, and in the scope of the original project,were
8 incurred and closed to plant as stated below.
9 Q. What were the total costs for the project?
10 A. Total costs closed to plant in 2023 and 2024 are $1,482,619 and$185,502, respectively.
11 Q. Please describe any significant project changes between what was described in the
12 IRP and how it's being described in this testimony.
13 A. There are no significant changes between the information reported in the IRP and in this
14 testimony.
15 FP-322390 - GR;6"PE-BOISE-E. COLUMBIA
16 Q. Please describe FP-322390 - GR;6"PE-Boise-E Columbia.
17 A. This project is for the installation of approximately 6,150 feet of 6 inch MDPE pipe near
18 the intersection of E Columbia Rd and S Eagle Rd in Boise, Idaho.
19 Q. Why did the Company undertake the project?
20 A. The Company undertook this project based on peak degree day pressure modeling that
21 showed a high likelihood of losing customers during a peak degree day event due to lower
22 pressure directly north of this project location. The project connected the area of low
PAGE 28 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I pressure with an area of adequate pressure to ensure more reliable service to customers
2 during a cold weather event.
3 Q. How will customers benefit from the project?
4 A. Customers in the area around this project will benefit from a decreased likelihood of
5 interrupted service, due to inadequate system pressures, during cold weather events.
6 Q. Did the Company consider alternative ways to meet the need for the project?
7 A. Yes, alternative routes were considered. However, this project consisted of the most direct
8 pipe routing between the adequate source of pressure and the modeled low-pressure
9 portion of the system.
10 Q. When was the project placed in service?
11 A. FP-322390 was placed in service in April of 2024.
12 Q. What were the total costs for the project?
13 A. Total costs closed to plant in 2024 are $1,194,240.
14 FP-323556 -FRL; IF; Pancheri Dr Bridge 6" HDD
15 Q. Please describe FP-323556.
16 A. The city of Idaho Falls was reconstructing a bridge on Pancheri Dr in Idaho Falls and
17 Intermountain's 6 inch HP line needed to be reinstalled under the river via Horizontal
18 Directional Drilling ("HDD"). There was not an opportunity for the line to be reinstalled
19 under the bridge deck, so the line was required to be bored under the river prior to
20 demolition of the bridge tentatively in September 2023.
21 Q. Why did the Company undertake the project?
22 A. The project was a forced relocation due to the existing pipeline in public right of way on
23 the bridge.
PAGE 29 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Q. How will customers benefit from the project?
2 A. Customers will benefit by continuing to receive natural gas service with this relocation.
3 Q. Did the Company consider alternative ways to meet the need for the project?
4 A. Intermountain reviewed the ability to abandon this line under the bridge and continue to
5 serve the existing customers. However, the abandonment would result in a shortfall in
6 supply and result in customer outages.
7 Q. When was the project placed in service?
8 A. The pipeline was placed into service in September 2023, the point at which it was in use
9 and useful. In 2024, additional costs related to, and in the scope of the original project,
10 were incurred and closed to plant as stated below.
11 Q. What were the total costs for the project?
12 A. Total costs closed to plant in 2023 and 2024 are $1,302,692 and -$31,783, respectively.
13 FP-323849 -WAPELLO COMPRESSOR LAND
14 Q. Please describe FP-323849 WAPELLO COMPRESSOR LAND.
15 A. This FP was for the purchase of approximately 40 acres of land near Wapello, Idaho for
16 the future installation of a new compressor station which is discussed in FP-321409.
17 Q. Why did the Company undertake the project?
18 A. This project is needed in conjunction with FP-321409 and FP-324783 to provide reliable
19 service to customers on the Idaho Falls lateral. System modeling showed an inability to
20 provide reliable service, due to low system pressures, as growth along the Idaho Falls
21 lateral continues. Therefore, a project to increase system capacity,pressures, and overall
22 reliability was needed.
PAGE 30 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Q. How will customers benefit from the project?
2 A. Customers will benefit from increased reliability and increased capacity on the Idaho Falls
3 Lateral.
4 Q. Did the Company consider alternative ways to meet the need for the project?
5 A. Yes, the Company analyzed the replacement or reinforcement of the existing 12 inch and
6 10 inch laterals that serve Idaho Falls. However, the cost for materials and labor for the
7 project outweighed the cost of a compressor station due to the mileage of pipe required to
8 match the capacity and pressure a compressor station can provide.
9 Q. When was the project placed in service?
10 A. FP-323849 was placed in service in October of 2023.
11 Q. What were the total costs for the project?
12 A. Total costs closed to plant in 2023 are $2,868,412.
13 Q. Please describe any significant project changes between what was described in the
14 IRP and how it's being described in this testimony.
15 A. The date this FP was initiated was May 31, 2023. The only changes between this testimony
16 and what was presented in the IRP is that the precise location of the property and cost of
17 the project would have been unknown at the time of the IRP.
2025 PRO FORMA ADDITIONS TO PLANT IN SERVICE—OVER$1 MILLION
18 FP-101001 - Gas Meters-Total Company IGC
19 Q. Please describe FP-101001 - Gas Meters-Total Company IGC.
20 A. The costs in this FP are for new meter purchases to measure customer gas usage.
21 Q. Why did the Company undertake the project?
22 A. This FP is necessary because meters help to ensure customers are billed accurately.
PAGE 31 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Q. How will customers benefit from the project?
2 A. The customer benefit of this project is that meters help to ensure customers are billed
3 accurately.
4 Q. Did the Company consider alternative ways to meet the need for the project?
5 A. No,because meters are the only way to accurately bill and therefore, they are required.
6 Q. Are there any offsetting O&M cost savings associated with this project?
7 A. No.
8 Q. What work has been completed and when will the project be placed in service?
9 A. This is a programmatic FP that will never close. Meters are purchased as needed for new
10 services and existing meter replacements throughout the year.
11 Q. What are the estimated costs for the project?
12 A. Total estimated project cost to close to plant in 2025 is $9,167,388.
13 FP-316020 -UG-GIS ESRI System Upgrade IGC
14 Q. Please describe FP-316020—UG-GIS ESRI System Upgrade IGC.
15 A. This is a significant software upgrade to the geographic information system("GIS") ESRI
16 platform due to substantial changes in the system architecture, tooling, and database
17 organization. ESRI is the platform used by Intermountain and is an industry standard
18 software suite. ESRI has moved to an upgraded version of the software to both modernize
19 the platform and to tailor it to the utility industry.
20 Q. Why did the Company undertake the project?
21 A. This upgrade was required by ESRI for all utilities in the industry who maintain a
22 connected network, as Intermountain does. The upgrade is a solution focused on utilities,
23 where the current version requires add-on applications to support utilities. The upgrades
PAGE 32 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I are necessary for Intermountain to maintain the value of its investment in the ESRI
2 software platform. This upgrade will enable Intermountain to consolidate business
3 processes, reduce reliance on third party software, simplify system integrations, improve
4 data quality, and move to a modern technology platform.
5 Q. How will customers benefit from the project?
6 A. Intermountain expects operational and, in turn, customer benefits to flow from the GIS
7 upgrade. ESRI GIS is a critical application and tool used by field employees,back-office
8 employees, engineering, operations, and management, and must be kept current for the
9 Company to operate. The upgraded ESRI platform is more standardized with a data model
10 designed with utilities in mind. Tooling is upgraded to leverage 64-bit software
11 architecture and integrations are standardized when delivering system-to-system interfaces.
12 The upgraded ESRI GIS application suite will allow Intermountain's employees to
13 continue to properly maintain the gas system,provide accurate information about the
14 system for decision making, analyze gas system data for proper planning, and to allow for
15 safe handling of gas emergencies. Intermountain's customers benefit from these essential
16 functions being done effectively through current technology, thus allowing for the safe and
17 reliable delivery of natural gas.
18 Q. Did the Company consider alternative ways to meet the need for the project?
19 A. Not as it relates to this GIS upgrade. Intermountain's current ESRI environment is going
20 end-of-life, and it is not a viable option to let the system operate without a necessary
21 upgrade or to be maintained without ESRI support. The only other option would be to
22 switch to another product vendor, which would necessitate a complete GIS system
23 replacement, and would be far more complex and costly.
PAGE 33 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Q. What work has been completed and when will the project be placed in service?
2 A. The project closed to plant in service in March 2025. There are some clean up items and
3 interface work with other systems that will be done in the first half of 2025.
4 Q. What are the estimated costs for the project?
5 A. Total estimated project cost to close to plant in 2025 is $3,899,367.
6 FP-318180, FP-318181 - System Safety and Integrity Program
7 Q. Why did the Company undertake the project?
8 A. Please see the explanation of the System Safety and Integrity Program included in the 2023
9 and 2024 Plant in Service Section under FP-318180 and FP-318181. Pipeline replacement
10 is typically the most viable option to remediate risks associated with corrosion, material
11 failure, weld/joint failure, equipment failure, and missing data threats. The SSIP program
12 addresses safety, reliability, and operational risks by replacing pipe systematically,where
13 Intermountain has determined that replacement is an appropriate action to reduce risk.
14 Q. How will customers benefit from the project?
15 A. SSIP replaces and eliminates early vintage plastic pipe and early vintage steel pipe prone to
16 corrosion, material failure, weld/joint failure, equipment failure, and missing data threats.
17 The replacement of these high-risk systems increases overall public safety and improves
18 system reliability for customers.
19 Q. Did the Company consider alternative ways to meet the need for the project?
20 A. Yes, but as noted, systematic pipe replacement is typically the most viable option for early
21 vintage plastic and steel pipe and, when feasible, Intermountain will still work jointly with
22 State, City, County, or general contractors performing highway, road, and underground
23 infrastructure replacement projects within the same vicinity. This collaboration eliminates
PAGE 34 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I duplication of work,provides cost savings, and limits long-term interruptions to
2 Intermountain's customers.
3 Q. Would you please describe the SSIP pipe replacement project that will be completed
4 in 2025?
5 A. Yes, Intermountain will be completing SSIP pipe replacement in Boise, Idaho in 2025.
6 Q. Would you please describe the Boise SSIP pipe replacement project?
7 A. The Boise SSIP pipe replacement project is a multi-year project primarily focusing on the
8 replacement of Pre-1983 early vintage plastic main and service lines with MDPE pipe.
9 Q. Why did the Company undertake the Boise SSIP pipe replacement project?
10 A. Boise was identified in 2023 as Intermountain's 2nd highest risk town with early vintage
11 plastic pipe and early vintage steel pipe in the state of Idaho, by the Intermountain's SSIP.
12 With the Parker SSIP pipe replacement completed in 2023, Boise became the next highest
13 risk town for replacement, starting in 2023.
14 Q. What is the project timeline for the Boise SSIP pipe replacement project?
15 A. The Boise SSIP pipe replacement project started in 2023 and will continue through 2027.
16 Q. What work has been completed and when will the project be placed in service?
17 A. The Boise SSIP pipe replacement project started in 2023 and will continue through 2027.
18 The phase identified for replacement in 2025 will be placed in-service before December
19 31, 2025.
20 Q. Are there any offsetting O&M cost savings associated with this project?
21 A. There are no offsetting O&M cost savings associated with this project.
22 Q. What are the estimated costs for the SSIP Main and Service Replacement project?
23 A. Total estimated SSIP project cost to close to plant in 2025 is $4,084,192.
PAGE 35 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Q. Does the Company expect SSIP efforts to continue?
2 A. Yes. Pipeline operators have a requirement to implement a DIMP that evolves and
3 matures to fit an operator's unique operating environment. The evolution of an operator's
4 DIMP takes time and resources to collect and analyze data to accurately identify the most
5 current high-risk pipe within any given distribution system. Once a system is prioritized
6 and selected, it typically requires multiple years to develop and execute an action plan for
7 full remediation or replacement. Based on this information, Intermountain expects the
8 SSIP program to continue for the foreseeable future.
9 Q. Please describe any significant project changes between what was described in the
10 IRP and how it's being described in this testimony.
11 A. There are no significant changes between the information reported in the IRP and in this
12 testimony. SSIP is described in the Infrastructure Replacement section of the IRP.
13 FP-318758-Rf-Nampa-4.1mi 1211S Ustick Rd Ph. 3
14 Q. Please describe FP-318758: 12" Ustick Phase 3
15 A. The 12 inch Ustick Phase 3 project connects an existing high pressure pipeline system to
16 the previously installed phases 1 and 2 of the total Ustick 12 inch plan. This is the final
17 phase of the total plan that extends the 500 psig MAOP system from the Nampa Gate
18 Station and Star Road into South Caldwell.
19 Q. Why did the Company undertake the project?
20 A. The new 12 inch pipeline is required to serve new core customer growth in the Canyon
21 County area of interest. The 12 inch pipeline allows for increased operating pressure and
22 higher flow delivered from the Nampa Gate Station.
PAGE 36 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Q. How will customers benefit from the project?
2 A. This project will allow for existing customers to continually receive reliable service while
3 also allowing for future core customer growth and demand.
4 Q. Did the Company consider alternative ways to meet the need for the project?
5 A. Three alternatives were considered to meet the need for this capacity enhancement. These
6 alternatives include Ustick Phase III, Ustick Uprate and an 8-inch High Pressure Extension
7 north of Ustick. Ustick Phase III,which this project is a component of,was chosen in 2021
8 as the largest capacity increasing alternative.
9 Q. Are there any offsetting O&M cost savings associated with this project?
10 A. There are no offsetting O&M cost savings associated with this project.
11 Q. When was the project placed in service?
12 A. The project was placed in service in December 2024, the point at which it was in use and
13 useful. In 2025 additional costs related to and in the scope of the original project will be
14 incurred and closed to plant as stated below.
15 Q. What were the total costs for the project?
16 A. Total estimated project cost to close to plant in 2025 is $1,368,683.
17 FP-321409 -RF-Idaho Falls-Compressor Sta IFL
18 Q. Please describe FP-321409 RF-Idaho Falls-Compressor Station IFL
19 A. This project is for the installation of a new compressor station, which will consist of two
20 compressor units on the Idaho Falls lateral. This project includes costs for building
21 materials, compressor skids, and all labor for design and installation.
PAGE 37 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Q. Why did the Company undertake the project?
2 A. This project is needed in conjunction with FP-324783 to provide reliable service to
3 customers on the Idaho Falls lateral. System modeling showed an inability to provide
4 reliable service, due to low system pressures, as growth along the Idaho Falls lateral
5 continues. Therefore, a project to increase system capacity,pressures, and overall
6 reliability was needed.
7 Q. How will customers benefit from the project?
8 A. Customers will benefit from increased reliability and increased capacity on the Idaho Falls
9 Lateral.
10 Q. Did the Company consider alternative ways to meet the need for the project?
11 A. Yes, the Company analyzed the replacement or reinforcement of the existing 12 inch and
12 10 inch laterals that serve Idaho Falls. However, the cost for materials and labor for the
13 project outweighed the cost of a compressor station due to the mileage of pipe required to
14 match the capacity and pressure a compressor station can provide.
15 Q. Are there any offsetting O&M cost savings associated with this project?
16 A. There are no offsetting O&M cost savings associated with this project.
17 Q. What work has been completed and when will the project be placed in service?
18 A. The project will be placed into service August 2025. To date, the building has been
19 designed and materials ordered. The conditional use permit for the site has been received
20 from the county and the building permit is currently under review. Construction of the site
21 is the only remaining task.
22 Q. What are the estimated costs for the project?
23 A. Total estimated project cost to close to plant in 2025 is $23,210,043.
PAGE 38 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Q. Please describe any significant project changes between what was described in the
2 IRP and how it's being described in this testimony.
3 A. There are no significant changes between the information reported in the IRP and in this
4 testimony.
5 FP-324562 -IGC-Picarro Leak Survey Equip 2025
6 Q. Please describe FP-324562.
7 A. This project is for the purchase of Picarro advanced mobile leak detection equipment.
8 Q. Why did the Company undertake the project?
9 A. This equipment is more sensitive than current equipment and allows employees to use the
10 equipment while driving instead of walking.
11 Q. How will customers benefit from the project?
12 A. Customers will benefit from the increased sensitivity of the equipment which will help
13 employees to identify more leaks and tighten the Company's distribution system to
14 increase customer safety.
15 Q. Did the Company consider alternative ways to meet the need for the project?
16 A. Intermountain considered three different vendors and performed pilots with each vendor
17 before making its selection. Picarro was chosen for its industry leading software, and
18 proven advanced leak detection technology, having been in the market for over 10 years.
19 Q. Are there any offsetting O&M cost savings associated with this project?
20 A. Yes, the Company anticipates saving O&M costs related to its leak survey efforts.
21 Performing a leak survey should take less time since employees will be driving instead of
22 walking. O&M cost savings anticipated for 2025 are $200,000.
PAGE 39 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Q. What work has been completed and when will the project be placed in service?
2 A. Work began the end of May and the project will be placed into service by June 2025.
3 Q. What are the estimated costs for the project?
4 A. Total estimated project cost to close to plant in 2025 is $1,206,840.
5 FP-324783 -INST MN-WAPELLO COMPRESSOR STA
6 Q. Please describe FP-324783 INST MN-WAPELLO COMPRESSOR STA
7 A. This project is for the installation of the inlet and outlet main for the Wapello Compressor
8 Station (FP-321409). The project costs include tie-ins to the existing system, several
9 automated and manual valves, material, and contractor labor.
10 Q. Why did the Company undertake the project?
11 A. This project is needed in conjunction with FP-321409 to provide reliable service to
12 customers on the Idaho Falls lateral. System modeling showed an inability to provide
13 reliable service, due to low system pressures, as growth along the Idaho Falls lateral
14 continues. Therefore, a project to increase system capacity,pressures, and overall
15 reliability was needed.
16 Q. How will customers benefit from the project?
17 A. Customers will benefit from increased reliability and increased capacity on the Idaho Falls
18 Lateral.
19 Q. Did the Company consider alternative ways to meet the need for the project?
20 A. Yes, the Company analyzed the replacement or reinforcement of the existing 12 inch and
21 10 inch laterals that serve Idaho Falls. However, the cost for materials and labor for the
22 project outweighed the cost of a compressor station due to the mileage of pipe required to
23 match the capacity and pressure a compressor station can provide.
PAGE 40 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Q. Are there any offsetting O&M cost savings associated with this project?
2 A. There are no offsetting O&M cost savings associated with this project.
3 Q. What work has been completed and when will the project be placed in service?
4 A. The project will be placed into service August 2025. To date, all long lead time items have
5 been ordered and the project drawings are being reviewed prior to bidding for construction.
6 Q. What are the estimated costs for the project?
7 A. Total estimated project cost to close to plant in 2025 is $2,240,792.
8 Q. Please describe any significant project changes between what was described in the
9 IRP and how it's being described in this testimony.
10 A. There are no significant changes between the information reported in the IRP and in this
11 testimony.
2025 PRO FORMA ADDITIONS TO PLANT IN SERVICE—OVER$200,000
12 FP-101003 - Gas Rel4ulators-Total Company IGC
13 Q. Please describe FP-101003.
14 A. The costs in this FP are for new regulator purchases to regulate pressure and provide
15 overpressure protection at customer premises.
16 Q. What are the estimated costs for the project?
17 A. Total estimated project cost to close to plant in 2025 is $735,010.
18 FP-317749 -HPSS Replacements IGC
19 Q. Please describe FP-317749
20 A. This funding project is for small distribution pressure pipeline projects to be installed to
21 eliminate high pressure service sets. This is done by connecting these services to the
22 distribution system rather than directly to our high-pressure system. Often these projects
PAGE 41 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I take advantage of opportunities that develop throughout the year and are not planned out
2 individually.
3 Q. What are the estimated costs for the project?
4 A. Total estimated project cost to close to plant in 2025 is $695,921.
5 FP-318098 -Dist Reg Station Growth IGC
6 Q. Please describe FP-318098
7 A. This funding project is for unplanned regulator stations related to new growth in the
8 Intermountain service territory.
9 Q. What are the estimated costs for the project?
10 A. Total estimated project cost to close to plant in 2025 is $200,412.
11 FP-318173 -Dist Reg Station Replace IGC
12 Q. Please describe FP-318173.
13 A. This project is for unplanned regulator station replacements. These might be due to city or
14 county projects that force the Company to relocate the station, damage from third parties,
15 or any other unforeseen circumstances that require replacement of a regulator station or
16 major components of a station.
17 Q. What are the estimated costs for the project?
18 A. Total estimated project cost to close to plant in 2025 is $801,295.
19 FP-318182 - Gas Cathodic Protection—ID
20 Q. Please describe the Gas Cathodic Protection project (FP-318182).
21 A. The Gas Cathodic Protection project provides corrosion control to the Company's buried
22 steel natural gas pipe from the effects of external corrosion. This includes the installation
23 of corrosion control protection devices, which include rectifiers, galvanic groundbeds,
PAGE 42 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I impressed current groundbeds, AC/DC mitigation, and test stations. Intermountain is
2 mandated by PHMSA to provide cathodic protection for its steel natural gas pipelines. The
3 Company's Corrosion Control department is responsible for the monitoring and annual
4 testing of our corrosion control systems.
5 Q. What are the estimated costs for the project?
6 A. Total estimated project cost to close to plant in 2025 is $453,922.
7 FP-318626-RF;BOI;R-40236;STATE ST PH II
8 Q. Please describe FP-318626
9 A. This project is for the installation of a new regulator station. This station will replace RS-
10 30201, which is currently installed at the intersection of Highway 16 and Highway 44.
11 This is part of a larger project to extend high pressure to downtown Boise (FP-318631 and
12 FP-318651).
13 Q. What are the estimated costs for the project?
14 A. Total estimated project cost to close to plant in 2025 is $283,761.
15 FP-318631 -RF;130I;R-40237;STATE ST PH II
16 Q. Please describe FP-318631
17 A. This project is for the installation of a new regulator. This station will replace RS-40168.
18 This is part of a larger project to extend high pressure to downtown Boise (FP-318626 and
19 FP-318651).
20 Q. What are the estimated costs for the project?
21 A. Total estimated project cost to close to plant in 2025 is $231,586.
PAGE 43 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I FP-318633 -RF-MER-4"PE STATE ST PH II
2 Q. Please describe FP-318633
3 A. This project is for the installation of approximately 8,300 feet of 4 inch Polyethylene
4 ("PE") main on Linder Road in Eagle, Idaho. This project is primarily due to forced
5 relocation of the existing main due to an Idaho Transportation Department("ITD")road
6 project on Linder that significantly conflicts with the location of the existing main.
7 Q. What are the estimated costs for the project?
8 A. Total estimated project cost to close to plant in 2025 is $312,930.
9 FP-318651 -RF-MER-6"PE STATE ST PH II
10 Q. Please describe FP-318651
11 A. This project is for the installation of approximately 12,100 feet of 6 inch PE main on State
12 Street. Installation of the main will allow for the retirement of several regulator stations
13 and the re-pressure testing of the existing 12 inch high pressure steel main on State Street.
14 This project is part of a larger plan to bring high pressure to downtown Boise.
15 Q. What are the estimated costs for the project?
16 A. Total estimated project cost to close to plant in 2025 is $898,041.
17 FP-323239 -RPL MN - SHORTED CASING—ID
18 Q. Please describe the Shorted Casing Replacement project (FP-323239).
19 A. The Shorted Casing replacement project identifies and replaces shorted casings. A steel
20 carrier installed inside a steel casing is required to be electrically isolated from the steel
21 casing. To determine if a steel carrier is electrically isolated from a steel casing, each
22 casing is tested annually to determine if the casing is shorted or electrically isolated. If a
23 casing is determined to be shorted, it must be mitigated or replaced before its status can be
PAGE 44 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I resolved as not shorted. Mitigation methods are a short-term remedial action as the metal-
2 to-metal contact may reoccur. Therefore, replacement or abandonment/removal are
3 preferred methods to minimize the threat of a shorted casing.
4 Q. What are the estimated costs for the project?
5 A. Total estimated project cost to close to plant in 2025 is $535,708.
6 FP-323246 - 2025 MAOP; RPL; 8" TM; ID FALLS
7 Q. Please describe the 8-inch Idaho Falls Transmission Line MAOP Reconfirmation
8 project (FP-323246).
9 A. The 8-inch Idaho Falls Transmission Line MAOP Reconfirmation project includes the
10 installation of a new regulator station near Lewisville, Idaho. The installation of this
11 regulator station will allow Intermountain to reduce the MAOP on the 8-inch Idaho Falls
12 Transmission Line from Lewisville, Idaho to St. Anthony, Idaho. Intermountain is
13 required to take actions to reconfirm the MAOP of previously untested transmission
14 pipelines and transmission pipelines lacking certain material or operational records, where
15 the records needed to substantiate the MAOP are not traceable,verifiable, and complete
16 ("TVC"). This segment of the 8-inch Idaho Falls Line currently lacks records necessary to
17 confirm the pipelines current MAOP, therefore reducing pressure on this pipeline segment
18 satisfies requirements for Intermountain to reconfirm the MAOP in accordance with 49
19 CFR Part 192.624.
20 Q. What are the estimated costs for the project?
21 A. Total estimated project cost to close to plant in 2025 is $645,424.
PAGE 45 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I FP-323537- GR; 6" HP; EAGLE; 4.5 MI; SVR PHI
2 Q. Please describe FP-323537.
3 A. This project is for the new main installation of 4.5 miles of 6 inch HP steel pipe to feed a
4 regulator station and the distribution mains to supply gas to the residential and commercial
5 customers in the Spring Valley Ranch development in Eagle near Highway 16 and Equest
6 Lane. In this project, 4.5 miles of 6 inch HP steel will run along Big Gulch Parkway from
7 Highway 16 to Aerie Way to the end of the first phase of this development.
8 Q. What are the estimated costs for the project?
9 A. Total estimated project cost to close to plant in 2025 is $479,552.
10 FP-323539 - GR; 6" PE; EAGLE; 3.81 MI; SVR PHI
11 Q. Please describe FP-323539.
12 A. This project is for the new main installation of 3.8 miles of 6 inch Distribution Pressure
13 ("DP") PE line along Big Gulch Parkway to supply gas to the residential and commercial
14 customers in the Spring Valley Ranch development in Eagle near Highway 16 and Equest
15 Lane. The 3.8 miles of 6 inch PE will have PE stubs placed at various locations along the
16 arterial to service the subdivisions and developments as they come online. The 3.8 miles of
17 6 inch PE will run along Big Gulch Pkwy from near the Farmer's Union Canal to Aerie
18 Way to the end of the first phase of this development.
19 Q. What are the estimated costs for the project?
20 A. Total estimated project cost to close to plant in 2025 is $286,107.
21 FP-323749 -RP; 8" GRAPE ST HDD;TRANSM
22 Q. Please describe FP-323749.
23 A. During Pipeline Patrol, a deficiency was found on the 8 inch pipeline span at Grape Street
PAGE 46 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I in Shoshone crossing the Little Wood River. The pipeline inside of the concrete support
2 cannot be inspected. The span will be replaced by HDD bore, which necessitates that the
3 valve and regulator site be moved back, away from the river, so that they can be tied into
4 the new crossing. The valve setting is necessary due to Transmission class location spacing
5 and cannot be eliminated. The Company acquired a new reg/valve site easement that is
6 needed to install a new irrigation riser outside the fence for the landowner. The
7 transmission facilities should have a 550 psig MAOP.
8 Q. What are the estimated costs for the project?
9 A. Total estimated project cost to close to plant in 2025 is $274,136.
10 FP-324039 - RP; AF; ABERDEEN GATE REG STATION
11 Q. Please describe FP-324039.
12 A. Intermountain plans to rebuild and relocate Regulator Station 60031 in American Falls to
13 maximize capacity in the Aberdeen 4 inch HP lateral and address electrical compliance
14 problems within the Gate Station.
15 Q. What are the estimated costs for the project?
16 A. Total estimated project cost to close to plant in 2025 is $239,071.
17 FP-324728 -FRL; 6" PE; KETCH; 4,500' HWY75 PH2
18 Q. Please describe FP-324728.
19 A. This project will include the replacement of 4,600 feet of the existing 4-inch steel line on
20 Highway 75 with 6-inch PE. This is between Elkhorn and Serenade Lane. This work is
21 being done due to highway widening that is impacting the Company's line and forcing it to
22 be relocated.
PAGE 47 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I Q. What are the estimated costs for the project?
2 A. Total estimated project cost to close to plant in 2025 is $516,104.
3 FP-324730 -FRL; 6" PE; KETCH; 2600' HWY75 PH3
4 Q. Please describe FP-324730.
5 A. This project was originally anticipated to be completed in 2026 and included the
6 replacement of 2,600 feet of the existing 4-inch steel line on Highway 75 with 6-inch PE.
7 This work was being done due to highway district work that was forcing the Company to
8 relocate the existing line. The work has since been moved forward to 2025 due to highway
9 department scheduling. Some miscellaneous steel laterals will also be replaced with PE
10 pipe at the same time. The total pipe replacement is anticipated to be approximately 2,600
11 feet.
12 Q. What are the estimated costs for the project?
13 A. Total estimated project cost to close to plant in 2025 is $428,267.
14 FP-324731 -FRL; 2"&3/4" SL; KETCH; HWY75
15 Q. Please describe FP-324731
16 A. Idaho Department of Transportation is relocating Highway 97 in 2024, 2025, and 2026 in
17 Ketchum, Idaho. In 2024, the bridge over Trailcreek,just south of River Road was bored
18 and steel service line replacements were completed. This funding project completes 794
19 feet of service line replacements.
20 Q. What are the estimated costs for the project?
21 A. Total estimated project cost to close to plant in 2025 is $211,144.
PAGE 48 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I FP-324998-RPL-BOISE-4" STL-RAWSON CANAL BRDG
2 Q. Please describe FP-324998
3 A. This project is for the replacement of the existing 4 inch crossing on the Rawson Canal
4 bridge. The existing crossing utilizes pipeline hangers on the bridge and is currently out of
5 compliance. The replacement plan includes replacing the existing crossing with an HDD
6 below the canal.
7 Q. What are the estimated costs for the project?
8 A. Total estimated project cost to close to plant in 2025 is $322,309.
9 FP-325401 - GR-IDAHO FALLS CLEAN PWR 6IN HP
10 Q. Please describe FP-325401.
11 A. This project is for the installation of approximately 3,900 feet of 6 inch HP main and
12 service to a proposed electric generation plant in Idaho Falls, Idaho
13 Q. What are the estimated costs for the project?
14 A. Total estimated project cost to close to plant in 2025 is $356,718.
15 FP-325407 - FRL; SH-44 & SH-16; 12" TRANS MAIN
16 Q. Please describe FP-325407 FRL; SH-44 & SH-16; 12" TRANS MAIN.
17 A. This project is a forced relocation of the inlet main to a regulator station located at the
18 intersection of State Highway 44 and State Highway 16. This project is required due to a
19 road project that conflicts with the Company's 12 inch transmission main.
20 Q. What are the estimated costs for the project?
21 A. Total estimated project cost to close to plant in 2025 is $757,999.
PAGE 49 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I FP-325423 - RP; 6" HP; NAMPA, 800' WEISER RIVER
2 Q. Please describe FP-325423 GAS MAIN REPLACEMENT WEISER, COVE
3 BRIDGE.
4 A. This project is a forced relocation of high-pressure main due to the Cove Bridge
5 replacement and the conflict between existing high-pressure main and bridge footings. The
6 project consists of replacing 4-inch high-pressure main with 6-inch high-pressure main
7 being directionally drilled under the Weiser River and tying in at both ends of the bridge
8 project limits.
9 Q. What are the estimated costs for the project?
10 A. Total estimated project cost to close to plant in 2025 is $710,858.
11 FP-325641 -Nampa LNG-Desulph Skid Valve Repl
12 Q. Please describe FP-325641.
13 A. At the Nampa LNG plant, existing automated valves on the purification skids (CO2 and
14 Desulfurization)have been on a continuous rebuild/maintenance program as the valves
15 actuate continuously during the liquefaction process. The valves have not been
16 manufactured for many years and the rebuild components are now becoming scarce. This
17 two-year valve replacement program will update each skid with non-obsolete components
18 for continued operations. The CO2 skid valves were replaced in 2024 and the
19 Desulfurization skid valves will be replaced in 2025. This project also replaces the
20 associated solenoids, tubing and insulation.
21 Q. What are the estimated costs for the project?
22 A. Total estimated project cost to close to plant in 2025 is $446,520.
PAGE 50 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I FP-325705 -INST MN MARBLE FRONT W, CALDWELL
2 Q. Please describe FP-325705.
3 A. This project involves tying two existing mains together on Marble Front Road and an
4 existing main on Aviation Way into Marble Front Road for betterment pressures in
5 Caldwell, Idaho.
6 Q. What are the estimated costs for the project?
7 A. Total estimated project cost to close to plant in 2025 is $401,323
8 FP-325706-RF MN MIDDLETON&LINCOLN CALDWELL
9 Q. Please describe FP-325706.
10 A. This project is for a pressure betterment due to significant residential and commercial
11 growth in North Caldwell. The project consists of installing approximately 10,600 feet of
12 4-inch distribution main, tying in at Middleton Road and Lincoln Road, running west to
13 Mason Road, then south to tie into Marble Front Road.
14 Q. What are the estimated costs for the project?
15 A. Total estimated project cost to close to plant in 2025 is $781,467.
16 FP-325707-RF MN Cherry Ln to IIth Ave, Nampa
17 Q. Please describe FP-325707.
18 A. This project is for a pressure betterment due to significant residential and commercial
19 growth in North Nampa. The project consists of installing approximately 7,000 feet of 4-
20 inch distribution main, tying in at Franklin Blvd and Cherry Lane, running east to I lth Ave
21 Ext N.
22 Q. What are the estimated costs for the project?
23 A. Total estimated project cost to close to plant in 2025 is $471,535.
PAGE 51 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I FP-325708-RF MN Cherry Ln to Idaho Cntr Nampa
2 Q. Please describe FP-325708.
3 A. This project is for a pressure betterment due to significant residential and commercial
4 growth in North Nampa. The project consists of installing approximately 6,000 feet of 4-
5 inch distribution main, tying in at 1 Ith Ave Ext N and Cherry Lane, running east to Idaho
6 Center Blvd.
7 Q. What are the estimated costs for the project?
8 A. Total estimated project cost to close to plant in 2025 is $418,858.
9 FP-325913 - FRL; 8" HP STL; ParkAtExpo; 3000'
10 Q. Please describe FP-325913 FRL; 8" HP STL; ParkAtExpo; 3000'.
11 A. This project is for a forced relocation of approximately 3,000 feet of 8 inch steel pipeline
12 due to conflicts with the elevation plans for the Park at Expo Idaho project.
13 Q. What are the estimated costs for the project?
14 A. Total estimated project cost to close to plant in 2025 is $863,516.
15 FP-326245 - 2025 RMU REPLACEMENT -ID
16 Q. Please describe the Remote Monitoring Unit Replacement project(FP-326245).
17 A. The Remote Monitoring Unit ("RMU") Replacement project replaces existing RMU's that
18 will lose cellular network connection in the immediate future due to AT&T sunsetting their
19 NB-IoT cellular network. RMU's are used to monitor cathodic protection rectifier and
20 critical bond sites to meet the requirements of 49 CFR Part 192.465(b) & (c). RMUs also
21 provide synchronized interruption of cathodic protection systems, allowing"instant-off'
22 pipe-to-soil potential readings to be recorded for annual testing required by 49 CFR Part
23 192.465(a) &Appendix D. Intermountain has 154 RMU's that require replacement. The
PAGE 52 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY

I 5G units will sunset at the end of March 2025 followed by the 4G units which does not
2 have an exact date.
3 Q. What are the estimated costs for the project?
4 A. Total estimated project cost to close to plant in 2025 is $325,290.
CONCLUDING REMARKS
5 Q. Does this conclude your testimony?
6 A. Yes, it does.
PAGE 53 OF 53
P.DARRAS,DI
INTERMOUNTAIN GAS COMPANY