20251223APPLICATION.pdf

INTERMOUNTAIN° RECEIVED
GAS COMPANY December 23, 2025
A Subsidiary of MDU Resources Group,Inc. I DAH O PUBLIC
In the Community to Serve® UTILITIES COMMISSION
December 23, 2025
Ms. Monica Barrios-Sanchez
Commission Secretary
Idaho Public Utilities Commission
P.O. Box 83720
Boise, ID 83720-0074
RE: Case No. INT-G-25-08
Dear Ms. Barrios-Sanchez:
Attached for consideration by this Commission is an electronic submission of Intermountain Gas
Company's ("Intermountain") 2025 Integrated Resource Plan("IRP").
Intermountain respectfully requests that the Commission acknowledge the 2025 IRP in accordance
with its rules. If you should have any questions regarding the filing,please don't hesitate to contact
me at(509) 528-9223 or [e-mail].
Sincerely,
Is/Michael Parvinen
Michael Parvinen
Director, Regulatory Affairs
Intermountain Gas Company
Enclosures

Intermountain Gas Company
Integrated Resource Plan
2025 — 2030
INTERMOUNTAIN ®R
GAS COMPANY
A Subsidiary of MDU Resources Group, Inc.
In the Community to Serve'
Integrated Resource Plan 2025— 2030

Table of Contents
1 Executive Summary....................................................................................... 1
1.1 Overview .................................................................................................................................................1
1.1.1 About the Company........................................................................................................................1
1.1.2 Customer Base............................................................................................................................... 1
1.1.3 The IRP Process...............................................................................................................................2
1.1.4 Demand ..........................................................................................................................................2
1.1.5 Supply& Delivery Resources ..........................................................................................................3
1.1.6 Optimization ...................................................................................................................................3
1.1.7 Intermountain Gas Resource Advisory Committee ........................................................................4
1.1.8 Summary.........................................................................................................................................5
1.1.9 Natural Gas and the National Energy Picture.................................................................................7
1.1.10 The Direct Use of Natural Gas................................................................................................... 7
1.1.11 Clean Energy Future.................................................................................................................. 8
2 Demand........................................................................................................ 11
2.1 Demand Forecast Overview................................................................................................................. 10
2.2 Residential & Commercial Customer Growth Forecast........................................................................ 11
2.2.1 The Base Case Economic Growth Scenario...................................................................................16
2.2.2 Population and Employment....................................................................................................... 17
2.2.3 Households ..................................................................................................................................19
2.2.4 Customer Growth Scenarios ....................................................................................................... 20
2.2.5 The Low Customer Growth Scenario........................................................................................... 20
2.2.6 The High Customer Growth Scenario.......................................................................................... 20
2.2.7 Residential Customer Forecast.................................................................................................... 21
2.2.8 Commercial Customer Forecast................................................................................................... 24
2.3 Heating Degree Days& Design Weather...............................................................................................27
2.3.1 Normal Degree Days.....................................................................................................................27
2.3.2 Design Degree Days......................................................................................................................27
2.3.3 Peak Heating Degree Day Calculation...........................................................................................28
2.3.4 Base Year Design Weather........................................................................................................... 28
2.3.5 Area Specific Degree Days ........................................................................................................... 30
Integrated Resource Plan 2025— 2030 ii

2.4 Large Volume Customer Forecast .........................................................................................................31
2.4.1 Introduction..................................................................................................................................31
2.4.2 Method of Forecasting..................................................................................................................32
2.4.3 Forecast Scenarios....................................................................................................................... 32
2.4.4 Contract Demand..........................................................................................................................33
2.4.5 "Load Profile"vs MDFQ............................................................................................................... 33
2.4.6 System Reliability..........................................................................................................................34
2.4.7 General Assumptions................................................................................................................... 34
2.4.8 Base Case Scenario Summary...................................................................................................... 34
2.4.9 High Growth Forecast Summary...................................................................................................36
2.4.10 Low Growth Forecast Summary................................................................................................... 37
3 Supply and Delivery Resources................................................................... 39
3.1 Overview .............................................................................................................................................. 39
3.2 Traditional Supply Resources ................................................................................................................40
3.2.1 Overview.......................................................................................................................................40
3.2.2 Background.................................................................................................................................. 40
3.2.3 Gas Supply Resource Options...................................................................................................... 41
3.2.4 Shale Gas.......................................................................................................................................44
3.2.5 Supply Regions..............................................................................................................................45
3.2.6 Export LNG................................................................................................................................... 48
3.2.7 Types of Supply............................................................................................................................ 48
3.2.8 Pricing.......................................................................................................................................... 49
3.2.9 Storage Resources....................................................................................................................... 50
3.2.10 Interstate Pipeline Transportation Capacity................................................................................ 55
3.2.11 Supply Resources Summary..........................................................................................................59
3.3 Capacity Release& Mitigation Process .................................................................................................60
3.3.1 Overview.......................................................................................................................................60
3.3.2 Capacity Release Process..............................................................................................................61
3.3.3 Mitigation Process........................................................................................................................62
3.4 Non-Traditional Supply Resources ........................................................................................................63
3.4.1 Diesel/Fuel Oil...............................................................................................................................64
3.4.2 Coal...............................................................................................................................................64
3.4.3 Wood Chips...................................................................................................................................64
Integrated Resource Plan 2025— 2030 iii

3.4.4 Propane ........................................................................................................................................65
3.4.5 Satellite/Portable LNG Equipment................................................................................................65
3.4.6 Renewable Natural Gas................................................................................................................66
3.4.7 Hydrogen ..................................................................................................................................... 66
3.5 Lost and Unaccounted For Natural Gas Monitoring..............................................................................68
3.5.1 Billing and Meter Audits...............................................................................................................68
3.5.2 Meter Rotation and Testing..........................................................................................................69
3.5.3 Leak Survey...................................................................................................................................69
3.5.4 Damage Prevention and Monitoring ........................................................................................... 69
3.5.5 Weather and Temperature Monitoring........................................................................................72
3.5.6 Summary.......................................................................................................................................72
3.6 Core Market Energy Efficiency ..............................................................................................................73
3.6.1 Residential & Commercial Energy Efficiency Programs................................................................73
3.6.2 Conservation Potential Assessment ............................................................................................ 73
3.6.3 Energy Efficiency Potential .......................................................................................................... 75
3.7 Large Volume Energy Efficiency.............................................................................................................80
3.8 Avoided Costs........................................................................................................................................82
3.8.1 Overview...................................................................................................................................... 82
3.8.2 Costs Incorporated....................................................................................................................... 82
3.8.3 Understanding Each Component................................................................................................. 83
4 Optimization................................................................................................ 84
4.1 Distribution System Planning ............................................................................................................... 84
4.1.1 Overview ..................................................................................................................................... 84
4.1.2 System Dynamics......................................................................................................................... 84
4.1.3 Network Design Fundamentals.................................................................................................... 84
4.2 Modeling Methodology........................................................................................................................ 85
4.2.1 Model Building Process................................................................................................................ 86
4.2.2 Usage Per Customer.................................................................................................................... 86
4.2.3 Fixed Network.............................................................................................................................. 87
4.2.4 Model Validation ......................................................................................................................... 88
4.2.5 Distribution System Planning Process.......................................................................................... 89
4.2.6 Distribution System Enhancements............................................................................................. 90
4.2.7 Distribution System Enhancement Considerations...................................................................... 91
Integrated Resource Plan 2025— 2030 iv

4.2.8 Distribution System Enhancement Selection Guidelines............................................................. 92
4.2.9 Capital Budget Process ................................................................................................................ 92
4.2.10 Conclusion............................................................................................................................... 94
4.3 Capacity Enhancements ....................................................................................................................... 95
4.3.1 Overview...................................................................................................................................... 95
4.3.2 Canyon County............................................................................................................................. 96
4.3.3 Central Ada County.....................................................................................................................96
4.3.4 State Street Lateral......................................................................................................................97
4.3.5 Sun Valley Lateral.........................................................................................................................99
4.3.6 Idaho Falls Lateral........................................................................................................................99
4.3.7 Other AOI................................................................................................................................... 104
4.3.8 Five-Year Planning and Timing of Capacity Enhancements ........................................................ 106
4.4 Load Demand Curves.......................................................................................................................... 107
4.4.1 Overview.................................................................................................................................... 107
4.4.2 Customer Growth Summary Observations—Design Weather—AII Scenarios.......................... 108
4.4.3 Core Distribution Usage Summary—Design and Normal Weather—AII Scenarios................... 109
4.4.4 Projected Capacity Deficits—Design Weather—AII Scenarios .................................................. 112
4.4.5 2023 IRP vs. 2025 IRP Common Year Comparisons................................................................... 115
4.5 Resource Optimization....................................................................................................................... 126
4.5.1 Introduction............................................................................................................................... 126
4.5.2 Functional Components of the Model....................................................................................... 126
4.5.3 PLEXOS°Optimization Model.................................................................................................... 126
4.5.4 Model Structure......................................................................................................................... 127
4.5.5 Demand Area Forecasts............................................................................................................. 129
4.5.6 Supply Resources....................................................................................................................... 131
4.5.7 Transport Resources.................................................................................................................. 133
4.5.8 Model Operation ....................................................................................................................... 133
4.5.9 Special Constraints..................................................................................................................... 134
4.5.10 Model Inputs......................................................................................................................... 134
4.5.11 Model Results........................................................................................................................ 136
4.5.12 Summary............................................................................................................................... 138
4.6 Planning Results ................................................................................................................................. 140
4.6.1 Overview.................................................................................................................................... 140
Integrated Resource Plan 2025— 2030 v

4.6.2 Distribution System Planning..................................................................................................... 140
4.6.3 Upstream Modeling................................................................................................................... 153
4.6.4 Conclusion...................................................................................................................................155
4.7 Infrastructure Replacement............................................................................................................... 156
4.7.1 Overview ................................................................................................................................... 156
4.7.2 American Falls Neely Bridge Snake River Crossing .................................................................... 156
4.7.3 Rexburg Snake River Crossing.................................................................................................... 156
4.7.4 Shoshone Sun Valley Transmission Line Replacement ............................................................. 157
4.7.5 System Safety and Integrity Program (SSIP) .............................................................................. 157
4.7.6 Transmission Re-Confirmation................................................................................................... 158
4.7.7 Shorted Casing Replacement or Abandonment Program (SCRAP)............................................ 159
5 Glossary...................................................................................................... 160
List of Tables
Table 1: Forecasted Customer Growth ............................................................................................................. 15
Table 2: Forecasted Total Customers................................................................................................................ 15
Table 3: Monthly Heating Degree Days............................................................................................................. 30
Table 4: Large Volume Therm Forecast- Base Case Scenario ........................................................................... 35
Table 5: Large Volume Therm Forecast- High Growth Scenario........................................................................36
Table 6: Large Volume Therm Forecast- Low Growth Scenario.........................................................................37
Table 7: Storage Resources.................................................................................................................................53
Table 8: Northwest Pipeline Transport Capacity................................................................................................56
Table 9: 2022- 2024 Billing and Meter Audit Results.........................................................................................69
Table 10: AOI Capacity Summary and Timing.....................................................................................................106
Table 11: Canyon County Design Weather Annual Usage...................................................................................109
Table 12: Canyon County Normal Weather Annual Usage..................................................................................109
Table 13: Central Ada Design Weather Annual Usage.........................................................................................109
Table 14: Central Ada Normal Weather Annual Usage.......................................................................................109
Table 15: Sun Valley Lateral Design Weather Annual Usage ...............................................................................110
Table 16: Sun Valley Lateral Normal Weather Annual Usage .............................................................................110
Table 17: Idaho Falls Lateral Design Weather Annual Usage...............................................................................110
Table 18: Idaho Falls Lateral Normal Weather Annual Usage..............................................................................110
Table 19: N.of State Street Lateral Design Weather Annual Usage.....................................................................111
Table 20: N.of State Street Lateral Normal Weather Annual Usage...................................................................111
Table 21:Total Company Design Weather Annual Usage..................................................................................111
Table 22:Total Company Normal Weather Annual Usage...............................................................................111
Table 23: Canyon County Design Day Deficit......................................................................................................112
Integrated Resource Plan 2025— 2030 vi

Table 24: Central Ada Design Day Deficit.......................................................................................................... 112
Table 25: Sun Valley Lateral Design Day Deficit................................................................................................. 113
Table 26: Idaho Falls Lateral Design Day Deficit................................................................................................ 113
Table 27: N.of State Street Lateral Design Day Deficit....................................................................................... 114
Table 28:Total Company Design Day Deficit..................................................................................................... 114
Table 29: 2025 IRP Total Company Design Day Peak Usage .............................................................................. 115
Table 30: 2023 IRP Total Company Design Day Peak Usage .............................................................................. 115
Table 31: 2023 IRP vs. 2025 IRP Total Company Design Day Peak Usage....................................................... 116
Table 32: 2025 IRP Total Company Storage Deliverability.............................................................................. 116
Table 33: 2023 IRP Total Company Storage Deliverability.............................................................................. 117
Table 34: 2023 IRP vs. 2025 IRP Total Company Storage Deliverability.................................................................. 117
Table 35: 2025 IRP Canyon County Design Weather and Physical Deliverability..................................................118
Table 36: 2023 IRP Canyon County Design Weather and Physical Deliverability.................................................118
Table 37: 2023 IRP vs. 2025 IRP Canyon County Design Weather and Physical Deliverability..........................119
Table 38: 2025 IRP Central Ada Design Weather and Physical Deliverability................................................. 120
Table 39: 2023 IRP Central Ada Design Weather and Physical Deliverability....................................................... 120
Table 40: 2023 IRP vs.2025 IRP Central Ada Design Weather and Physical Deliverability.................................... 121
Table 41: 2025 IRP Sun Valley Lateral Design Weather and Physical Deliverability ........................................... 121
Table 42: 2023 IRP Sun Valley Lateral Design Weather and Physical Deliverability ........................................... 122
Table 43: 2023 IRP vs.2025 IRP Sun Valley Lateral Design Weather and Physical Deliverability......................... 122
Table 44: 2025 IRP Idaho Falls Lateral Design Weather and Physical Deliverability....................................... 123
Table 45: 2023 IRP Idaho Falls Lateral Design Weather and Physical Deliverability....................................... 123
Table 46: 2023 IRP vs.2025 IRP Idaho Falls Lateral Design Weather and Physical Deliverability.......................... 124
Table 47: 2025 IRP N. of State Street Lateral Design Weather and Physical Deliverability............................ 124
Table 48: 2023 IRP N. of State Street Lateral Design Weather and Physical Deliverability............................ 125
Table 49: 2025 IRP vs. 2025 IRP N. of State Street Lateral Design Weather and Physical Deliverability........ 125
Table 50: 2025 IRP Canyon County Design Weather Delivery Deficit............................................................. 146
Table 51: 2023 IRP Canyon County Design Weather Delivery Deficit............................................................. 146
Table 52: 2023 IRP vs. 2025 IRP Canyon County Design Weather Delivery Deficit ........................................ 147
Table 53: 2025 IRP Central Ada Design Weather Delivery Deficit................................................................... 147
Table 54: 2023 IRP Central Ada Design Weather Delivery Deficit .................................................................. 147
Table 55: 2023 IRP vs. 2025 IRP Central Ada Design Weather Delivery Deficit.............................................. 148
Table 56: 2025 IRP Sun Valley Lateral Design Weather Delivery Deficit......................................................... 148
Table 57: 2023 IRP Sun Valley Lateral Design Weather Delivery Deficit......................................................... 148
Table 58: 2023 IRP vs. 2025 IRP Sun Valley Lateral Design Weather Delivery Deficit.................................... 149
Table 59: 2025 IRP Idaho Falls Lateral Design Weather Delivery Deficit........................................................ 149
Table 60: 2023 IRP Idaho Falls Lateral Design Weather Delivery Deficit........................................................ 149
Table 61: 2023 IRP vs. 2025 IRP Idaho Falls Lateral Design Weather Delivery Deficit.................................... 150
Table 62: 2025 IRP N. of State Street Lateral Design Weather Delivery Deficit.............................................. 150
Table 63: 2023 IRP N. of State Street Lateral Design Weather Delivery Deficit.............................................. 150
Table 64: 2023 IRP vs. 2025 IRP N. of State Street Lateral Design Weather Delivery Deficit......................... 151
Table 65: 2025 IRP Total Company Design Weather Delivery Deficit............................................................. 151
Table 66: 2023 IRP Total Company Design Weather Delivery Deficit............................................................. 151
Table 67: 2023 IRP vs. 2025 IRP Total Company Design Weather Delivery Deficit......................................... 152
Table68: Regional LNG Projects ..................................................................................................................... 154
Integrated Resource Plan 2025— 2030 i

List of Figures
Figure1:The IRP Process.....................................................................................................................................4
Figure 2: Intermountain Gas System Map........................................................................................................... 6
Figure 3: Base Case Forecasted Growth by Area of Interest............................................................................. 13
Figure 4:Customer Growth Forecast—Residential & Commercial................................................................... 13
Figure 5: Customer Growth Forecast—Base Case: 2023 IRP vs. 2025 IRP.........................................................14
Figure 6:Canyon County Total Customer Forecast- Residential.......................................................................21
Figure 7: Central Ada Total Customer Forecast—Residential............................................................................21
Figure 8:Sun Valley Lateral Total Customer Forecast—Residential..................................................................22
Figure 9: Idaho Falls Lateral Total Customer Forecast—Residential .................................................................22
Figure 10: N. of State Street Total Customer Forecast—Residential.................................................................23
Figure 11:Total Company Customer Forecast—Residential .............................................................................23
Figure 12: Canyon County Total Customer Forecast—Commercial...................................................................24
Figure 13: Central Ada Total Customer Forecast—Commercial........................................................................24
Figure 14: Sun Valley Lateral Total Customer Forecast—Commercial ..............................................................25
Figure 15: Idaho Falls Lateral Total Customer Forecast—Commercial..............................................................25
Figure 16: N. of State Street Total Customer Forecast—Commercial...............................................................26
Figure 17:Total Company Customer Forecast—Commercial............................................................................26
Figure 18: Design Heating Degree Days............................................................................................................. 29
Figure 19: Large Volume Therms-2023 IRP Forecasted vs Actuals...................................................................32
Figure 20: Natural Gas Sources...........................................................................................................................41
Figure 21: Natural Gas Consumption by Sector.................................................................................................42
Figure 22: Shale Gas Production Trend...............................................................................................................43
Figure 23: US Lower 48 States Shale Plays.........................................................................................................44
Figure24: Supply Pipeline Map..........................................................................................................................46
Figure 25: Natural Gas Sources...........................................................................................................................48
Figure 26: Intermountain Price Forecast as of 05/07/2025............................................................................... 50
Figure 27: Intermountain Storage Facilities....................................................................................................... 51
Figure 28: Map-Pacific Northwest Pipelines .................................................................................................... 57
Figure 29: Damage Rates per 1,000 Locates by District .................................................................................... 70
Figure 30: Intermountain Locate Requests by District.......................................................................................71
Figure 31: Intermountain Total Damages by District......................................................................................... 71
Figure 32:Guidehouse:Types of Savings Potential .......................................................................................... 75
Figure 33: Guidehouse Analysis 2025: Savings Potential.................................................................................. 76
Figure 34:Guidehouse Analysis 2025: Achievable Potential as a Percent of Total Sales................................. 76
Figure 35: Guidehouse Savings Potential Scenarios.......................................................................................... 77
Figure 36:Guidehouse Analysis 2025: Four Scenarios of Achievable Potential ............................................... 77
Figure 37: Guidehouse Analysis 2025 ............................................................................................................... 78
Figure 38: Guidehouse Analysis 2025 ............................................................................................................... 79
Figure 39: Large Volume Website Login ........................................................................................................... 80
Figure 40: Natural Gas Usage History................................................................................................................ 81
Integrated Resource Plan 2025— 2030 ii

Figure 41: Peak Heating Degree Days...............................................................................................................88
Figure 42: Distribution System Planning Process Flow.....................................................................................93
Figure 43: State Street Lateral Capacity Limiter................................................................................................97
Figure 44: State Street Lateral Phase II Update.................................................................................................98
Figure 45: Idaho Falls Lateral Capacity Limiter.................................................................................................100
Figure 46: Idaho Falls Lateral Blackfoot Compressor.......................................................................................101
Figure 47: Idaho Falls Lateral Proposed Compressor Location........................................................................102
Figure 48: Idaho Falls Lateral Compressor Suction Proposed Pipeline............................................................103
Figure 49: IGC Natural Gas Modeling System Map..........................................................................................128
Figure 50: IGC Laterals from Zone 24...............................................................................................................129
Figure 51: 2025 LDC Total Company Design Weather Base Case ....................................................................130
Figure 52: IGC Supply Model Example .............................................................................................................131
Figure 53: IGC Storage Model Example............................................................................................................132
Figure 54: IGC Transport Model Example ........................................................................................................133
Figure55:Transport Input Summary...............................................................................................................136
Figure 56: Lateral Summary by Year................................................................................................................137
Figure 57: Annual Traditional Supply Resources Results.................................................................................137
Figure 58: Annual Transportation Resources Results ......................................................................................138
Figure 59: LDC Design Base Case—Canyon County..........................................................................................141
Figure 60: LDC Design Base Case—Central Ada ...............................................................................................142
Figure 61: LDC Design Base Case—Sun Valley Lateral......................................................................................143
Figure 62: LDC Design Base Case—Idaho Falls Lateral .....................................................................................144
Figure 63: LDC Design Base Case— N. of State Street Lateral..........................................................................145
Figure 64: 2026 Design Base Case—Total Company........................................................................................153
Integrated Resource Plan 2025— 2030 iii

I. Executive Summary
1.1 Overview
Natural gas continues to be the fuel of choice in Idaho. Southern Idaho's manufacturing plants,
commercial businesses, new homes and electric power peaking plants, all rely on natural gas to
provide an economic, efficient, environmentally friendly, comfortable form of heating energy.
Intermountain Gas Company(Intermountain, IGC, or Company) encourages the wise and efficient
use of energy in general and, in particular, natural gas for end uses across Intermountain's
service area.
The Integrated Resource Plan (IRP) is a document that describes the currently anticipated
customer demand conditions over a five-year planning horizon, the anticipated resource
selections to meet that demand, and the process for making resource decisions. Forecasting
the demand of Intermountain's growing customer base is a regular part of Intermountain's
operations, as is determining how to best meet the load requirements brought on by this
demand. Public input is an integral part of the IRP planning process. The demand forecasting
and resource decision making process is ongoing and accordingly the Company files with the
Idaho Public Utilities Commission an update to the IRP every two years. This IRP represents a
snapshot in time similar to a balance sheet. It is not meant to be a prescription for all future
energy resource decisions, as conditions will change over the planning horizon impacting areas
covered by this plan. The planning process described herein is an integral part of
Intermountain's ongoing commitment to make the wise and efficient use of natural gas an
important part of Idaho's energy future.
1.1.1 About the Company
Intermountain Gas, a subsidiary of MDU Resources Group, Inc., is a natural gas local distribution
company that was founded in 1950. The Company served its first customer in 1956.
Intermountain is the sole distributor of natural gas in southern Idaho. Its service area extends
across the entire breadth of southern Idaho as illustrated in Figure 2 (see page 6), an area of
50,000 square miles. At the end of 2020, Intermountain served approximately 444,600 total
customers in 76 communities through a system of over 13,300 miles of transmission, distribution
and service lines. In 2024, approximately 851 million therms were delivered to customers and
additional transmission, distribution, and service lines were added to accommodate new
customer additions and maintain service for Intermountain's growing customer base.
1.1.2 Customer Base
The economy of Intermountain's service area is based primarily on agriculture and related
industries. Major crops are potatoes, milk and sugar beets. Major agricultural-related industries
include food processing and production of chemical fertilizers. Other significant industries are
electronics, general manufacturing and services and tourism.
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Intermountain provides natural gas sales and service to two major markets: the
residential/commercial market and the large volume market. The Company's residential and
commercial customers use natural gas primarily for space and water heating. Intermountain's
large volume customers transport natural gas through Intermountain's system to be used for
boiler and manufacturing applications. Large volume demand for natural gas is strongly influenced
by the agricultural economy and the price of alternative fuels. During 2020, nearly 50% of the
throughput on Intermountain's system was attributable to large volume sales and transportation.
1.1.3 The IRP Process
Intermountain's Integrated Resource Plan is assembled by a talented cross-functional team from
various departments within the Company. The IRP begins with a five-year forecast that considers
customer demand and supply and delivery resources. The optimization model used in the
development of the IRP identifies potential deficits and considers all available resources to meet
the needs of Intermountain's customers on a consistent and comparable basis. A high-level
overview of the process is described below. Each step in the process will be outlined in greater
detail in later sections of this document.
1.1.4 Demand
As a starting point, Intermountain develops base case, high growth, and low growth scenarios to
project the customer demand on its system for both core market and large volume customers.
The core market includes residential and commercial customers. Large volume customers are
high usage customers that are not eligible for residential or commercial service.
For the core market, the first step involves forecasting customer growth for both residential and
commercial customers. Next, Intermountain develops design weather. Then the Company
determines the core market usage per customer using historical usage, weather and geographic
data. The usage per customer number is then applied to the customer forecast under design
weather conditions to determine the core market demand.
To forecast both therm usage and contract demand for large volume customers, the Company
analyzes historical usage, economic trends, and direct input from large volume customers. This
approach is appropriate given the small population size of these customer classes. Because large
volume customers typically use natural gas for industrial processes,weather data is not generally
considered.
Both core market and large volume demand forecasts are developed by areas of interest (AOI)
and then aggregated to provide a total company perspective. Analyzing demand by AOI allows
the Company to consider factors specifically related to a geographic area when considering
potential capacity enhancements.
Page 2

1.1.5 Supply & Delivery Resources
After determining customer demand for the five-year period,the Company identifies and reviews
currently available supply and delivery resources. Additionally, the Company includes in its
resource portfolio analysis various non-traditional resources as well as potential therm savings
resulting from its energy efficiency program.
1.1.6 Optimization
The final step in the development of the IRP is the optimization modeling process,which matches
demand against supply and deliverability resources by AOI and for the entire Company to identify
any potential deficits. Potential capacity enhancements are then analyzed to identify the most
cost effective and operationally practical option to address potential deficits. The Planning
Results section shows how all deficits will be met over the planning horizon of the study. Figure
1 provides a visual overview of the IRP process.
Page 3

�- • Supply : Delivery Resources Forecast Transportation
Capacity&Storage Distribution System
Residential&Commercial Overview
Customer Growth Natural Gas Supplies
Design Non-Traditional
Residential& Weather Resources
Commercial Usage Energy Efficiency:
Per Customer Residential&
Commercial
Industnal Demand 1
Demand Supply & Deliverability
Load Demand Curves
L4 I Optimization Modeling
System
Enhancements
Figure 1: The IRP Process
1.1.7 Intermountain Gas Resource Advisory Committee
To enhance the Integrated Resource Plan development, the Company established the
Intermountain Gas Resource Advisory Committee (IGRAC). The intent of the committee is to
provide a forum through which public participation can occur as the IRP is developed.
Advisory committee members were solicited from across Intermountain's service territory as
representatives of the communities served by Intermountain. Exhibit 1, Section A, is a sample of
the invitation tojoin the committee. Committee members have varied backgrounds in regulation,
economic development, and business.
Intermountain held its IGRAC meetings on a virtual platform to ensure that committee members
from across the state could safely and easily participate. A total of four virtual meetings were
held in 2025 between the months of July and December. Included in Exhibit 1 are meeting
minutes and presentations from the meetings.
After each meeting, for members who were unable to attend, an email containing the materials
covered was sent out. The Company provided a comment period after each meeting to ensure
feedback was timely and could be incorporated into the IRP. Intermountain also established an
email account where feedback and information requests could be managed. Finally, the
Page 4

Company has a dedicated webpage where meeting minutes, presentations, and video recordings
are presented shortly after each IGRAC meeting.'
1.1.8 Summary
Through the process explained above, Intermountain analyzed residential, commercial and large
volume demand growth and the consequent impact on Intermountain's distribution system using
design weather conditions under various scenarios. Forecast demand under each of the
customer growth scenarios was measured against the available natural gas delivery systems to
project the magnitude and timing of potential delivery deficits, both from a total company
perspective as well as an AOI perspective.The resources needed to meet these projected deficits
were analyzed within a framework of traditional, non-traditional and energy efficiency options
to determine the most cost effective and operationally practical means available to manage the
deficits. In utilizing these options, Intermountain's core market and firm transportation
customers can continue to rely on safe, reliable, affordable firm service both now and in the
future.
'See:https://www.intgas.com/rates-services/rates-tariffs/integrated-resource-plan/
Page 5

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Page 6

1.1.9 Natural Gas and the National Energy Picture
The blue flame. Curling up next to a natural gas fireplace, starting the morning with a hot shower,
coming home to a warm house. The blue flame of natural gas represents warmth and comfort,
and provides warmth and comfort in the cleanest, safest, most affordable way possible.
Natural gas remains the cleanest-burning fossil fuel, producing primarily heat and water vapor.
In 2025, U.S. natural gas consumption is projected to reach 91.4 billion cubic feet per day(Bcf/d),
driven by residential, commercial, and industrial sectors.' Distribution system CO2 emissions
remain low, with annual emissions under 0.1 million metric tons of CO2e, thanks to ongoing
infrastructure upgrades.2
The U.S. natural gas industry has added over 815,000 miles of pipeline since 1990, serving more
than 77 million customers. These investments have helped reduce methane emissions from
distribution systems by over 69% since 1990, according to the EPA.
Natural gas pipelines remain the safest and most efficient transportation method,outperforming
rail and truck. Safety and reliability are prioritized at every stage, from design to maintenance.3
Natural gas is also cost-effective. As of 2025, households using natural gas save an average of
$1,068 annually compared to electric-only homes. Despite rising global demand, U.S. prices are
forecasted to average around $3.90/MMBtu, thanks to record production levels.4
The U.S. has at least a century's worth of natural gas reserves, ensuring long-term supply
stability.'
1.1.10 The Direct Use of Natural Gas
The direct use of natural gas refers to employing natural gas at the end-use point for space
heating, water heating, and other applications. This is opposed to the indirect use of natural gas
to generate electricity which is then transported to the end-use point and employed for space or
water heating. The direct use of natural gas is 91% efficient from production to the consumer
end-use, compared to an efficiency of only 36%for the indirect use of natural gas.
As electric generating capacity becomes more constrained in the Pacific Northwest, additional
peak generating capacity will primarily be natural gas fired. Direct use will mitigate the need for
https://www.forbes.com/sites/rrapier/2025/04/02/us-natural-gas-in-2025-record-supply-and-demand/
2 https://bipartisanpolicy.org/download/?file=/wp-
content/uploads/2025/09/BPC_Natural_Gas_Report_September-2025.pdf
3 https://bipartisanpolicy.org/download/?file=/wp-
content/uploads/2025/09/BPC_Natural_Gas_Report_September-2025.pdf
4 https://www.forbes.com/sites/rrapier/2025/04/02/us-natural-gas-in-2025-record-supply-and-demand/
5 https://www.igu.org/igu-reports/global-gas-report-2025
Page 7

future generating capacity. If more homes and businesses use natural gas for heating and
commercial applications, then the need for additional generating resources will be reduced.
From a resource and environmental perspective, the direct use of natural gas makes the most
sense. More energy is delivered using the same amount of natural gas, resulting in lower cost
and lower CO2 emissions. This direct, and therefore, more efficient natural gas usage will serve
to keep natural gas prices, as well as electricity prices, lower in the future.
Intermountain plays a critical role in providing energy throughout southern Idaho.The Company's
residential customers use over 201.5 million therms a year for space heating applications. If this
demand had to be served by electricity, it would mean that Intermountain's residential
customers would require approximately 5,079,000 megawatt hours a year to replace the natural
gas currently used to heat their homes. This would require nearly doubling the total residential
electric load currently being supplied in the region. This scenario would prove a considerable
burden for both electric generation and transmission.
Ultimately, using natural gas for direct use in heating applications is the best use of the resource,
and mitigates the need for costly generation and infrastructure expansion across the U.S. electric
grid.
1.1.11 Clean Energy Future
Natural gas is not only safe, reliable and affordable, but the natural gas distribution system will
also be a critical component in delivering clean energy in the future. Intermountain is actively
involved in the research and development of low- and zero-carbon energy technologies through
its participation in Gas Technology Institute (GTI) and the Low-Carbon Resources Initiative (LCRI).
LCRI is a joint venture of GTI and the Electric Power Research Institute. Its mission is to accelerate
the deployment of the low- and zero-carbon energy technologies that will be required for deep
decarbonization. LCRI is specifically targeting advances in the production, distribution, and
application of low-carbon, alternative energy carriers and the cross-cutting technologies that
enable their integration at scale. These energy carriers - which include hydrogen, ammonia,
synthetic fuels, and biofuels - are needed to enable affordable pathways to achieve deep carbon
reductions across the energy economy. The LCRI is focused on technologies that can be
developed and deployed beyond 2030 to support the achievement of a net zero emission
economy by 2050.
Intermountain is also playing an important role in the growth and development of the emerging
Renewable Natural Gas (RNG) industry. The Company's RNG Facilitation agreement allows
Intermountain to provide access to its distribution system for RNG producers to transport RNG
to their end use customers. RNG takes a waste stream that is currently emitting greenhouse
gasses, captures it, and puts it to a beneficial end use. Although RNG is currently more expensive
Page 8

than traditional natural gas, as the technology matures the Company anticipates the costs will
continue to decrease which will make it a viable supply option for customers in the future.
Page 9

2. Demand
2.1 Demand Forecast Overview
The starting point for resource planning is developing a reliable forecast of future load
requirements. This involves more than simply projecting overall growth, it requires an
understanding of how many customers will require service, how much natural gas those
customers are likely to use, and the weather conditions that will influence demand. To capture
the full picture, contracted maximum deliveries to large industrial customers are also
incorporated into the demand forecast.
Intermountain's approach integrates several key elements, including forecasts of customer
counts, calculations of gas usage per customer, and a range of weather profiles. Each of these is
explored in greater detail later in this document. By combining them in different ways,
Intermountain develops separate demand forecast scenarios for core market customers, which
are then used to test system needs under a range of possible conditions. When combined with
large volume customers, these scenarios create a total company demand outlook. This
perspective is essential for planning because it includes not only monthly and annual loads but
also daily usage patterns, including peak demand events. Such detail allows Intermountain to
assess whether existing supply arrangements and delivery capacity are sufficient under varying
demand situations. Further discussion of these forecasts is provided in the following sections.
To ensure resource planning is both comprehensive and precise, Intermountain also evaluates
distinct segments of its distribution system, referred to as Areas of Interest (AOI). These AOIs
capture the diversity of customer demand across the service territory, and the results of each
analysis are then aggregated to form a company-wide perspective. The AOIs used for planning
purposes are as follows:
• The Canyon County Area: serves core market customers in Canyon County.
• Central Ada County Area: serves core market customers in Ada County between Chinden
Boulevard and Victory Road (north—south) and between Maple Grove Road and Black Cat
Road (east—west).
• The Sun Valley Lateral: serves core market customers in Blaine and Lincoln Counties.
• The Idaho Falls Lateral: serves core market customers in Bingham, Bonneville, Fremont,
Jefferson, and Madison Counties.
• The State Street Lateral: serves core market customers in Ada County north of the Boise
River, bounded on the west by Kingsbury Road (west of Star) and on the east by State
Highway 21.
• The All Other Segment: serves core market customers in Ada County not included in the
State Street Lateral or Central Ada Area, as well as customers in Bannock, Bear Lake,
Caribou,Cassia, Elmore,Gem,Gooding,Jerome, Minidoka, Owyhee, Payette, Power,Twin
Falls, and Washington Counties.
Page 10

2.2 Residential & Commercial Customer Growth Forecast
This section of Intermountain's IRP describes and summarizes the residential and commercial
customer growth forecast for the years 2025 through 2030.This forecast provides the anticipated
magnitude and direction of Intermountain's residential and commercial customer growth by the
identified Areas of Interest (AOI) for Intermountain's service territory. Customer growth is the
primary driving factor in Intermountain's five-year demand forecast contained within this IRP.
In this IRP, Intermountain utilized an ARIMAX model (Autoregressive Integrated Moving Average
with Exogenous Variables) to forecast residential and commercial customer counts. This model
combines a regression component with an ARIMA error structure, allowing it to incorporate
explanatory variables such as the number of households, employment forecasts, and other
drivers described below. ARIMA-based models are widely used for time series forecasting
because they capture both nonseasonal and seasonal patterns in the data. The nonseasonal
components are represented by the parameters (p, d, q), while the seasonal components are
represented by(P, D, Q).These components are automatically selected to minimize the corrected
Akaike Information Criterion (AICc), ensuring the best-performing model for the data. The
ARIMAX approach is particularly beneficial because it accounts for both historical patterns and
external drivers, improving forecast accuracy. The household variable reflects actual and
forecasted household growth by county within Intermountain's service territory, and
employment data captures actual and projected full- and part-time jobs by place of work.
Generally, increases in household counts are associated with increases in residential customers,
while rising employment tends to correlate with growth in commercial customer counts, hence
their inclusion as explanatory variables. To capture annual seasonality, Fourier terms with K
harmonics are also included, each harmonic adds a pair of sine and cosine terms that help
represent seasonal patterns. A deterministic trend component may be added to account for any
remaining underlying trend, and lagged versions of household and/or employment data may also
be incorporated. Whether a variable is included depends on its impact on model performance
relative to other tested models. Coefficients are estimated by the modeling software to best
represent the relationship between each explanatory variable and the outcome variable. Each
county and customer type combination in Intermountain's service territory is modeled
separately. The general customer count forecast model is shown below,though not every model
includes all the explanatory variables listed. As noted, the final combination of explanatory
variables, lag structures of those explanatory variables, a trend component, ARIMA error
components, and Fourier terms is determined based on model performance during the selection
process. This approach differs from the previous IRP, and the equation below is representative
only.
Page 11

The customer forecast model is as follows:
Customerst = flo + fl,HHt + fl2Empt + Trendt + Fourier("year",K)t + ilt
Where:
• t: time index.
• Customerst: Total customer count at time t.
• HHt: Number of households at time t.
• Empt: Employment at time t.
• Trendt: Deterministic trend component at time t.
o This captures the long-term gradual growth or decline of customers over
time.
• Fourier("year",K)t: Captures yearly seasonality using K harmonics at time t.
o These terms capture the predictable seasonal swings (e.g., yearly highs or
lows).
• rit is the error term modeled as an ARIMA(p,d,q)(P,D,Q) process with:
p nonseasonal autoregressive terms,d nonseasonal di f f erencing,
q nonseasonal moving average terms,P seasonal autoregressive
terms,D seasonal di f f erencing,Q seasonal moving average terms.
o This component jointly models the error term using an ARIMA process to
capture autocorrelation and other patterns not explained by the explicitly
modeled variables. By incorporating this structure into the model, forecast
accuracy improves and the remaining innovations behave like white noise.
Page 12

Similar to the 2023 IRP, Intermountain's growth projections remain strong. Figure 3 below
illustrates the combined residential and commercial customer additions by AOI.
Base Case Forecasted Growth by Area of Interest
3,500
3,000
2,500
2,000
u'
1,500
a
1,1] 11
UNTY SUN VALLEY IF LATERAL N OF STATE ST CENTRAL ADA MIX ALL OTHER
■2025 2026 ■2027 ■2028 ■2029 ■2030
Figure 3:Base Case Forecasted Growth by Area of Interest
The forecast includes three economic scenarios: base case, low growth, and high growth. IGC has
incorporated these scenarios into the customer growth model and developed three five-year
core market customer growth forecasts. Figure 4 below displays the annual additional customer
projections for each of the three economic scenarios.
Customer Growth Forecast- Residential & Commercial
14,000
12,000
�1
10,000
E
0 8,000
6,000
's
LIE:
2026 2027 2028 2029 2030
�IDw Growth Base Case High Growth
Figure 4: Customer Growth Forecast-Residential& Commercial
Page 13

Figure 5 below shows the difference in the base case forecasted annual customer growth
between the 2023 IRP and the 2025 IRP, where the two forecasts overlap.
Customer Growth Forecast-Residential&Commercial
Base Case:2023 IRP vs 2025 IRP
1z o00
11,000
10,000
m
9,000
r
a
8,000
7,000
6,000
2026 2027 2028
�20231RP --*--20251RP
Figure 5: Customer Growth Forecast—Base Case: 2023 IRP vs. 2025 IRP
Page 14

The following two tables present the results of the five-year customer growth forecast for each
economic scenario. Table 1 shows the projected customer growth under each scenario, while
Table 2 displays the forecasted total number of customers for each scenario.
Forecasted Customer Growth
2025 2026 2027 2028 2029 2030
Low Growth 9,476 5,780 5,073 5,665 5,918 5,541
Base Case 10,291 8,385 7,809 8,495 8,840 8,542
High Growth + 11,105 I 10,998 10,595 11,409 I 11,890 11,715
Table 1:Forecasted Customer Growth
Forecasted Total Customers
2025 2026 2027 2028 2029 2030
Low Growth 432,632 438,412 443,485 449,150 455,068 460,608
Base Case 433,446 441,832 449,641 458,136 466,975 475,517
High Growth 434,260 445,258 455,853 467,263 479,152 490,867
Table 2:Forecasted Total Customers
The following sections explore the different components of the customer forecast in greater
detail.
Page 15

2.2.1 The Base Case Economic Growth Scenario
Under the Base Case Scenario of the Idaho Economic Forecast, it is projected that Idaho will
continue to be an attractive environment for future economic, population, and household
growth.
From 2015 to 2019, Idaho's nonfarm employment grew at a strong pace, with an average year-
over-year percent change of 2.91%. This amounted to a gain of about 136,600 jobs over that
period. Population growth was also a major driver of economic expansion leading up to the
COVID-19 pandemic. At the start of 2020, Idaho entered the year with a historically strong
economy, including a record-low unemployment rate of 2.5%. However,the onset of the COVID-
19 pandemic caused a sharp slowdown. On March 25, 2020, Governor Brad Little issued a
statewide stay-at-home order, leading to the closure of nonessential businesses. By April, the
state's unemployment rate surged to 11.8%,the highest in recorded history, leaving over 100,000
Idahoans unemployed and reducing nonfarm employment by 78,500 jobs, effectively erasing
four years of job growth in a single month. Industries such as leisure and hospitality, other
services, education and health services, and information were among the hardest hit.
Despite this severe disruption, the recovery began quickly. By May 2020, Idaho launched the
"Rebound Idaho" phased reopening plan. The unemployment rate declined to 9%, and nonfarm
employment rebounded by 3.3%, regaining roughly a year's worth of job growth. Overall, Idaho
still managed a year-over-year gain of about 1.5% in nonfarm jobs in 2020, an increase of roughly
15,310. From 2021 through 2024, the recovery accelerated. Total nonfarm employment
increased year-over-year at an average rate of 3.31%, adding about 143,242 jobs. In 2021, Idaho
recorded its largest annual gain in nonfarm employment since 1994, with an increase of 5.95%
(about 61,698 jobs). This strong, and relatively rapid rebound, highlights an economy with
continued upward momentum and strong future growth prospects.
Population growth has closely paralleled these employment gains. Even through the pandemic,
Idaho's population growth remained robust. From 2019 to 2021, the state posted the highest
year-over-year percentage change in population in the nation, averaging about 2.37% annually,
an increase of roughly 97,470 people over three years. The 2021 gain of 2.98% was the largest
single-year increase since 1994.
Although growth has moderated slightly since then, it remains strong. The Bureau of Labor
Statistics estimates that Idaho's population grew by 1.36% in 2023 (about 26,823 people) and
1.52% in 2024 (about 30,497 people). Even at these lower rates, Idaho's growth still exceeded
the national weighted average of about 0.98%, meaning the state continued to outpace most of
the country. Much of this growth has been driven by domestic migration from more expensive
and densely populated states such as Oregon, Washington, and California. Overall, Idaho's rapid
population growth has fueled job creation, strengthened the economy, and positioned the state
for continued expansion.
Page 16

2.2.2 Population & Employment
Idaho is expected to maintain its strong growth trajectory through the second half of the decade,
though at a more measured pace than the rapid expansion seen immediately after the pandemic.
Between 2025 and 2030, the state's population is projected to increase by approximately
112,858 residents, reflecting an average annual growth rate of 0.92%. Over the same period,
nonfarm employment is forecast to expand by roughly 93,179 jobs, an average annual increase
of 1.27%.
Growth will remain highly concentrated in Ada and Canyon Counties. Together, these counties
are projected to account for the majority of new residents and jobs, with an additional 74,550
people (an average annual growth rate of 1.51%) and 54,582 jobs (an average annual increase of
1.67%). This represents about two-thirds of Idaho's projected population growth and about
58.58% of job creation statewide.
In the central part of the state, where the Company provides service to Blaine and Lincoln
Counties through the Sun Valley Lateral, population is projected to rise by 1,366, an average
annual growth rate of 0.73%, while employment is expected to grow by 1,161 jobs, also an
average annual increase of 0.73%.These gains make up 1.25%of Idaho's total growth. In eastern
Idaho, within the Idaho Falls Lateral (covering Bingham, Bonneville, Fremont, Jefferson, and
Madison Counties), population is projected to increase by 18,627, an average annual growth rate
of 1.05%, representing 16.50% of statewide growth. Employment in this area is expected to
expand by 11,705 jobs, an average annual increase of 1.20%, making up 12.56% of the total
projected gains in Idaho.
The Education and Health Services supersector has been one of Idaho's fastest-growing
industries. From 2019 to 2024, employment increased by 15.23% (28,287 jobs), reflecting an
average annual growth rate of 3.41%. Projections for 2025-2030 indicate continued strength,
with an additional 26,930 jobs expected, an average annual increase of 2.70%. Most of this
growth will come from health care and social assistance (21,776 jobs). Employment gains in Ada
and Canyon Counties are expected to total 15,047 jobs, an average annual increase of 3.19%,
accounting for more than half of statewide growth in this sector. Blaine and Lincoln Counties are
projected to add 265 jobs, an average annual increase of 2.03%, while the Idaho Falls Lateral is
forecast to see an increase of 3,999 jobs, an average annual increase of 2.35%.
This expansion is supported by structural drivers such as population growth, demographic shifts,
policy support, and new investment in hospitals, schools, and assisted living facilities. For the
Company, this implies sustained demand for natural gas in residential, commercial, and
institutional settings.
Manufacturing recovered quickly after the pandemic, adding 5,725 jobs between 2019 and 2024,
including gains of 2,013 jobs in 2021 and 3,346 jobs in 2022. Looking ahead, growth is projected
to slow, with only 1,676 additional jobs statewide from 2025-2030, an average annual increase
of 0.34%. Ada and Canyon Counties are projected to see a decline of 505 jobs, an average annual
Page 17

decrease of 0.27%, while Blaine and Lincoln Counties are expected to add 71 jobs, an average
annual increase of 1.63%.The Idaho Falls Lateral is forecasted to add 636 jobs, an average annual
increase of 1.05%. Although statewide manufacturing growth is modest, the sector continues to
demonstrate resilience. Challenges include labor shortages, skills gaps, and competition from
faster-growing industries, while automation and technology are reshaping production and
allowing output growth with fewer workers.
Construction also experienced significant momentum in recent years, fueled by population
inflows and housing demand. Between 2019 and 2024, employment in the sector increased by
20,640 jobs, reflecting an average annual growth rate of 4.29%. For the period 2025-2030,
Woods& Poole forecasts a gain of 882 jobs, an average annual increase of 0.16%,while the Idaho
Department of Labor projects a much stronger 25.6% increase between 2022 and 2032.
Regardless of the precise pace, construction activity is expected to remain robust as new
residents drive demand for housing, schools, health care facilities, and infrastructure. These
developments could translate into additional natural gas demand in both residential and
commercial applications.
The combined sectors of retail trade, transportation and warehousing, wholesale trade, and
utilities added nearly 38,000 jobs between 2019 and 2024, reflecting an average annual growth
rate of 3.26%. From 2025 to 2030, growth is projected to moderate, with an increase of 8,766
jobs statewide, an average annual increase of 0.66%. Ada and Canyon Counties are expected to
account for 6,339 of those jobs, an average annual increase of 0.91%, underscoring their central
role in Idaho's logistics and distribution networks.
Broadly defined, the services industries are expected to lead Idaho's job growth. These include
professional and technical services, education, health care, government, accommodation and
food services, and other services. Together, they added 65,148 jobs between 2019 and 2024,
reflecting an average annual growth rate of 2.41%. Looking forward, the sector is projected to
add 57,298 jobs from 2025 to 2030, an average annual increase of 1.85%, accounting for over
61% of statewide job creation. Of this growth, 34,367 jobs are projected in Ada and Canyon
Counties, an average annual increase of 2.53%, making up nearly 60% of the total gains for this
group in the State. Blaine and Lincoln Counties are expected to add 616 jobs, an average annual
increase of 0.97%, while the Idaho Falls Lateral is forecast to add 7,801 jobs, an average annual
increase of 1.79%.
Although growth is expected to slow somewhat compared with the extraordinary post-pandemic
rebound, Idaho remains on a trajectory of steady expansion. Factors such as moderating wage
gains, slower population growth, and a shifting balance between retirees and working-age
residents will temper momentum, but strong demand for services, continued in-migration, and
investment in key industries should keep the state among the nation's stronger performers.
These trends point to continued demand for the Company's services.
Page 18

2.2.3 Households
Woods & Poole defines households as:
Occupied housing units. A housing unit may be a single-family home, an
apartment, a group of rooms, or a single room occupied as separate living
quarters. The occupants may consist of one family, a single individual, multiple
families living together, or unrelated persons sharing the same space. All
individuals are part of a household except those who live in group quarters,
such as prisons, nursing homes, dormitories, or military barracks. Average
household size is calculated by subtracting the group-quarters population from
the total population and dividing by the number of households.
In previous IRPs, population was used as an explanatory variable in residential customer models.
For this IRP, household counts are used instead, as they provide a more accurate measure of
potential residential service connections. While population growth may reflect more people
moving into the state, multiple individuals often share the same home, meaning that household
growth aligns more closely with utility service needs. Household data also better reflects
development trends and provides greater stability and consistency with regional planning
assumptions. For example, if a city adds 1,000 new homes, that translates directly into 1,000
potential new residential customers, regardless of whether 2,000 or 3,000 people move into
those homes.
Between 2019 and 2024, Idaho added 94,435 households, with an average annual growth rate
of 2.25%. The surge in 2022 and 2023 marked record highs, reflecting strong population inflows
during, and immediately, following the pandemic. Looking ahead, growth is expected to remain
strong but at a more moderate pace. From 2025 through 2030, Idaho is projected to add 69,161
households, with an average annual increase of 1.16%. Ada and Canyon Counties are expected
to account for about 51.88% of this increase, adding 35,879 households at an average annual
growth rate of 1.89%. The Sun Valley Lateral (Blaine and Lincoln Counties) is forecasted to
contribute 806 new households, representing 1.17% of the statewide total and growing at an
average annual rate of 1.01%. The Idaho Falls Lateral is projected to add 8,474 households, an
average annual growth rate of 1.43%, or 12.25% of the statewide increase.
Page 19

2.2.4 Customer Growth Scenarios
In addition to the base case forecast, which represents the most likely outcome, two alternative
scenarios are developed: a low customer growth scenario and a high customer growth scenario.
These scenarios provide a structured way to evaluate uncertainty in future customer growth.
Both are constructed using the historical standard deviation of annual customer growth rates,
ensuring that they are grounded in observed patterns and remain straightforward to audit and
reproduce.
2.2.5 The Low Customer Growth Scenario
The low growth scenario applies a downward adjustment equivalent to one standard deviation
below the base case customer growth rate. This adjustment is converted into a monthly
compounding growth factor by taking the twelfth root of the annual growth rate, which is then
applied iteratively by using the cumulative product function to simulate the effect of
compounding overtime.The resulting vector provides a potential trajectory that reflects a slower
pace of customer additions compared with the base forecast.
This scenario assumes that Idaho's long-standing trend of strong in-migration slows relative to
recent history. Migration out of Oregon, Washington, and California would increasingly be
captured by neighboring states such as Utah, Nevada, and Arizona, reflecting patterns observed
in the 1990s and early 2000s. Idaho could also face additional headwinds if a major employer
were to close or relocate operations, reducing its ability to attract job seekers. In this scenario,
weaker economic growth, fewer employment opportunities, and slower population inflows
would all contribute to more limited customer growth for the Company.
2.2.6 The High Customer Growth Scenario
The high growth scenario increases the base case forecast by one standard deviation above the
base case customer growth rate, again applying a compounding monthly factor derived from the
annual growth adjustment. This produces a trajectory that reflects faster customer growth than
in the base case.
Under this scenario, Idaho captures a larger share of both business relocations and in-migration
from neighboring states. Firms based in California, Oregon, and Washington could increasingly
seek out Idaho for its relatively lower taxes, operating costs, and regulatory environment. This
would continue a pattern that has occurred over the past three decades, when Nevada, Arizona,
and Utah attracted substantial economic and population growth through business relocations
and migration flows. In this case, Idaho is assumed to become a more prominent destination,
drawing not only businesses but also individuals and families seeking more affordable housing
and less congestion than in neighboring coastal states. The result would be stronger growth in
Page 20

both households and employment levels, resulting in a higher number of natural gas customers
than in the base case.
2.2.7 Residential Customer Forecast
The following graphs show the forecasted residential customer counts by AOI and total Company
for each of the growth scenarios using the methodology previously outlined.
Canyon County Total Customer Forecast - Residential
P,7
OF—
so Ox.
75 C00
1
H 70'000
65.000
60,000
Ton .o.� a
slOW e —�•..
Figure 6: Canyon County Total Customer Forecast-Residential
767
Central Ada Total Customer Forecast - Residential
69,OT
,OOJ
6s,oc�
6],000
10 7U"
6S,CM
69,000
l7,000
Ow -+ w-NCR
Figure 7: Central Ada Total Customer Forecast—Residential
Page 21

Sun Valley Lateral Total Customer Forecast - Residential
13,400
13,200
13,000
yr 12,800
E
0
I12,600 --
v
0
~ 12,400
12,200
12,000 -
11,800
1 3 4 5 6
flow — Base —*—High MEMEL
Figure 8: Sun Valley Lateral Total Customer Forecast—Residential
Idaho Falls Lateral Total Customer Forecast - Residential
71AO
69.000
67.000
65 000
63.000
V
3
61.000
59.000
57000
55.000
1 4 5 6
Figure 9:Idaho Falls Lateral Total Customer Forecast—Residential
Page 22

N. of State Street Lateral Total Customer Forecast - Residential
700.,.0.
0
0
65.000
63,000
61.000
S9.000
57,000
SS,000
2025 2027 202E 2019 YOlO
—0—Eau —0—r+6n
Figure 10:N. of State Street Lateral Total Customer Forecast—Residential
Total Company Customer Forecast - Residential
r476s.000
4SS,000
445,000
435,000 -
¢ .125,000
415,000
r
405,000
395,000
385,000
3»,000 _
2M 2026 �0
Figure I1: Total Company Customer Forecast—Residential
Page 23

2.2.8 Commercial Customer Forecast
The following graphs show the forecasted commercial customer counts by A01 and total
Company for each of the growth scenarios using the methodology previously outlined.
Canyon County Total Customer Forecast - Commercial
s.noa
:�j
s.eoo
s aoo
i
s,00a
•eoo
t NX
Figure 12: Canyon County Total Customer Forecast—Commercial
Central Ada Total Customer Forecast- Commercial
.,.00
..300
4,M
4.200
4.150
v
b ..100
..0S0
4.000
3.950 --
3,900
.,.n ]OI7 200t 70Q! :O10
—W—LM --o—!r! —*—Koh
Figure 13: Central Ada Total Customer Forecast—Commercial
Page 24

Sun Valley Lateral Total Customer Forecast - Commercial
1.580
1.560
1,540
ON
1.490
1.460
1,440 --
1.4:0
w
1 I 7 4 5 6
IL
��taw -+—Bau w•�yu
Figure 14: Sun Valley Lateral Total Customer Forecast—Commercial
Idaho Falls Lateral Total Customer Forecast - Commercial
F.000.
7.800
7.600
t
7.400
7,:00
7.000
6,800
4 G
Figure 1 S:Idaho Falls Lateral Total Customer Forecast—Commercial
Page 25

N. of State Street Lateral Total Customer Forecast - Commercial
sum
5 000
A,QLX
3
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a Sop --- --- --- --
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2025 ::gib 2027 202E 2029 20l0
Figure 16:N. of State Street Lateral Total Customer Forecast—Commercial
Total Company Customer Forecast - Commercial
CO-)r�2
CCU
4E 4C OCU
6
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18 LKK
37.X0D
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Figure 17: Total Company Customer Forecast—Commercial
Page 26

2.3 Heating Degree Days & Design Weather
intermountain's demand forecast captures the influence weather has on system loads by using
Heating Degree Days (HDDs) as an input. HDDs are a measure of the coldness of the weather
based on the extent to which the daily mean temperature falls below a reference temperature
base. HDD values are inversely related to temperature, which means that as temperatures
decline, HDDs increase. The standard HDD base, and the one Intermountain utilizes in its IRP, is
657 (also called HDD65). As an example, if one assumes a day where the mean outdoor
temperature is 307, the resulting HDD65 would be 35 (i.e. 65°F base minus the 307 mean
temperature = 35 Heating Degree Days). Two distinct groups of heating degree days are used in
the development of the IRP: Normal Degree Days and Design Degree Days.
Since Intermountain's service territory is composed of a diverse geographic area with differing
weather patterns and elevations, Intermountain uses weather data from seven National Oceanic
and Atmospheric Administration (NOAA) weather stations located throughout the communities
it serves. This weather data is weighted by the quantity of residential and commercial customers
in each of the weather districts to best reflect the temperatures experienced across the service
territory. Several AOIs are also addressed specifically by this IRP. Those segments are assigned
unique degree days as discussed in further detail below.
2.3.1 Normal Degree Days
A Normal Degree Day is calculated based on historical data, and represents the weather that
could reasonably be expected to occur on a given day. The Normal Degree Day that
Intermountain utilizes in the IRP is computed based on weather data for the thirty years ended
December 2024. The HDD65 for January 1st for each year of the thirty-year period is averaged
to come up with the average HDD65 for the thirty-year period for January 1st. This method is
used for each day of the year to arrive at a year's worth of Normal Degree Days.
2.3.2 Design Degree Days
Design Degree Days represent the coldest temperatures that can be expected to occur for a given
day. Design Degree Days are a critical input for modelling the level of customer demand that may
occur during extreme cold or "peak" weather events. For IRP load forecasting purposes,
Intermountain makes use of design weather assumptions.
Intermountain's design year is based on the premise that the coldest weather experienced for
any month, season, or year could occur again. The Company reviewed NOAA temperature data
over the period of record and found the coldest twelve consecutive months in Intermountain's
service territory to be the 1984/1985 heating season (October 1984 through September 1985).
Page 27

That year, with certain modifications discussed below, represents the base year for design
weather.
2.3.3 Peak Heating Degree Day Calculation
Intermountain engaged the services of Dr. Russell Qualls, Idaho State Climatologist,to perform a
review of the methodology used to calculate design weather, and to provide suggestions to
enhance the design weather planning. Dr. Qualls assisted Intermountain in developing a method
to calculate probability-derived peak HDD values, as well as in designing the days surrounding
the peak day.
To develop the peak heating degree day, or coldest day of the design year, Dr. Qualls fitted
probability distributions to as much of the entire period of record from seven weather station
locations (Caldwell, Boise, Hailey,Twin Falls, Pocatello, Idaho Falls, and Rexburg) as was deemed
reliable. From these distributions he calculated monthly and annual minimum daily average
temperatures for each weather location, corresponding to different values of exceedance
probability. Two probability distributions were fitted, a Normal Distribution, and a Pearson Type
III (133) distribution. Dr. Qualls suggested it is more appropriate for Intermountain to use the P3
distribution as it is more conservative from a risk reduction standpoint. The final climatology
report can be found attached as Exhibit 3.
According to Dr. Qualls, "selecting design temperatures from the values generated by these
probability distributions is preferable over using the coldest observed daily average temperature,
because exceedance probabilities corresponding to values obtained from the probability
distributions are known. This enables IGC to choose a design temperature, from among a range
of values,which corresponds to an exceedance probability that IGC considers appropriate for the
intended use".
Intermountain used Dr. Qualls' exceedance probability results to review the data associated with
both the 50 and 100 year probability events. After careful consideration of the data,
Intermountain determined that the company-wide 50 year probability event, which was a 78
degree day, would be appropriate to use in the design weather model.
2.3.4 Base Year Design Weather
To create a design weather year from the base year, a few adjustments were made to the base
design year. First, since the coldest month of the last thirty years was December 1985, the
weather profile for December 1985 replaced the January 1985 data in the base design year. For
planning purposes, the aforementioned peak day event was placed on January 15th.
To model the days surrounding the peak event, Dr. Qualls suggested calculating a 5-day moving
average of the temperatures for the past thirty-year period to select the 5 coldest consecutive
Page 28

days from the period. December 1990 contained this cold data. The coldest day of the peak
month (December 1985) was replaced with the 78 degree day peak day. Then, the day prior and
three days following the peak day,were replaced with the 4 cold days surrounding the December
1990 peak day.
While taking a closer look at the heating degree days used for the Load Demand Curves (LDCs),
the Company noticed that the design HDDs in some of the shoulder and summer months were
lower than the normal weather HDDs for those months. This occurred because, while the 1985
heating year was overall the coldest on record,the shoulder months were in some cases warmer
than normal. Manipulating the shoulder and summer month design weather to make it colder
would add degree days to the already coldest year on record, creating an unnecessary layer of
added degree days. Intermountain decided not to adjust the summer and shoulder months of
the design year.
After design modifications were completed, the total design HDD curve assumed a bell-shaped
curve with a peak at mid-January (see Figure 18 below). This curve provides a robust projection
of the extreme temperatures that can occur in Intermountain's service territory.
HEATING DEGREE DAYS
1,800
aO 1,600
W
cu.' 1,400
W
1,200
z
1,000
a
W
= 800
}
J
600
Z
400
J
200
O
0
'et e� ac1 e` e�`JacJ
`10
he4,
ka
Actual Heating Year 1985 Weighted Normal(30 Year Rolling) -Design Year
Figure 18:Design Heating Degree Days
Page 29

The resulting Normal, Base Year (1985), and Design Year degree days by month are outlined in
the table below:
HeatingMonthty - - - Days
Actual Heating Year Weighted Normal(30
1985 Year Rolling) Design Year
October 604 443 604
November 827 786 826
December 1,338 1,085 1,338
January 1,483 1,092 1,633
February 1,180 896 1,178
March 972 699 970
April 413 492 411
May 231 258 231
June 62 80 62
July - - -
August 1 36 7 36
September 306 120 306
Total 7,452 5,958 7,595
Table 3: Monthly Heating Degree Days
2.3.5 Area Specific Degree Days
As noted earlier in this IRP, Intermountain has identified certain areas of interest.These are areas
Intermountain carefully manages to ensure adequate delivery capabilities either due to a unique
geographic location, customer growth, or both.
The temperatures in these areas can be quite different from each other and from the total
company. For example, the temperatures experienced in Idaho Falls or Sun Valley can be
significantly different from those experienced in Boise or Pocatello. Intermountain continues to
work on improving its capability to uniquely forecast loads for these distinct areas. A key driver
to these area specific load forecasts is area specific heating degree days.
Intermountain has developed Normal and Design Degree Days for each of the areas of interest.
The methods employed to calculate the Normal and Design Degree Days for each AOI mirrors the
methods used to calculate Total Company Normal and Design Degree Days.
Page 30

2.4 Large Volume Customer Forecast
2.4.1 Introduction
The Large Volume (LV) customer group is comprised of approximately 152 of the largest
customers on Intermountain's system from both an annual therm use and a peak day basis.
Only customers that use at least 200,000 therms per year are eligible for Intermountain's LV
tariffs. The LV tariffs provide two firm delivery services: a bundled sales tariff (LV-1) and a
distribution system only transport tariff (T-4). The Company also offers an interruptible
distribution system only transportation tariff(T-3).
The LV customers are made up of a mix of industrial and commercial loads and, on average,
they account for nearly 49% of Intermountain's 2024 annual throughput and 24% of the
projected 2025 design Base Case peak day. Nearly 97% of 2026 LV throughput reflects
distribution system-only transportation tariffs where customer-owned natural gas supplies are
delivered to Intermountain's various Citygate stations for ultimate redelivery to the customers'
facilities.
Because the LV customers' volumes account for such a large part of Intermountain's overall
throughput, the method of forecasting these customers' overall usage is an important part of
the IRP. These customers' growth and usage patterns differ significantly from the residential
and commercial customer groups in two significant ways. First, the LV customers' gas usage
pattern as a whole is not nearly as weather sensitive as the core market customers, meaning
that forecasting their volumes using standard regression techniques based on projected
weather does not provide statistically significant results. Secondly, the total LV customer count
is so few that it falls below the number required to provide an adequate statistical
population/sample size.
Therefore, Intermountain has developed and utilizes an alternate, but very accurate, method of
forecasting based on historical usage, economic trends, and direct input from these Large
Volume customers. Figure 19 shows a comparison of total actual LV therm use against base
case forecast therm use from the 2023 IRP for the years 2023—2025.
Page 31

2023 IRP
Comparison of Large Volume Forecast vs Actual
450,000 -
400,000 —
- 350,000 —
300,000
0 250,000
0
0
0 200,000
150,000
100,000 —
50,000
0
2023 2024 2025
Actual —2023 IRP Forecast
Figure 19: Large Volume Therms-2023 IRP Forecasted vs Actuals
2.4.2 Method of Forecasting
Intermountain maintains a historical therm use database containing over thirty years of
monthly therm use data. The LV forecasting methodology begins by assessing each LV
customer's monthly usage for the most recent three years. Then a representative twelve-
month period is selected as the "base" year. Typically, more weight is applied to the most
recent twelve-month period available unless known material variations would suggest a
different base year.
2.4.3 Forecast Scenarios
For the IRP, Intermountain prepared three separate LV monthly gas consumption forecasts
(Base Case, High Growth and Low Growth). The Base Case forecast started with the adjusted
base year data as described above. That data was then combined with assumptions based on
the most likely economic trend to develop during the five-year Base Case forecast. Other
available data, including economic development organizations and alternate economic
forecasts/assumptions were utilized to develop the High Growth and Low Growth scenarios.
For ease of analysis, the 152 existing and up to ten projected new customers (per the High
Growth scenario) were combined into six homogeneous market segments:
Page 32

2025 Customers by Market Segment:
• 18 potato processors
• 52 other food processors including sugar, milk, beef, and seed companies
• 3 chemical and fertilizer companies
• 33 light manufacturing companies including electronics, paper, and asphalt companies
• 33 schools, hospitals, and other weather sensitive customers
• 13 "other" companies including transportation-related businesses
2.4.4 Contract Demand
Every LV customer is required to sign a contract to receive service under any of the LV tariffs.
An important element of the firm LV-1 sales and T-4 transportation contracts is the Maximum
Daily Firm Quantity ("MDFQ") which reflects the agreed upon maximum amount of daily gas
and/or capacity the Company must be prepared to provide that firm LV customer on any given
day including the projected system peak day that would occur during design weather.
T-3 interruptible customers' contracts include a Maximum Daily Quantity or "MDQ" which only
represents the maximum amount of gas the Company's service line and meter can flow.
Because T-3 service is interruptible, Intermountain makes no assurances of the amount of
distribution capacity that will be available on any given day. For peak event modeling purposes,
the IRP assumes T-3 customers are reduced to minimal emergency plant-heat only. This IRP
uses the term contract demand (CD) when referencing both MDFQ and MDQ. Intermountain
utilized LV customer CDs as they existed on January 1, 2025 for the beginning point for Base
Case CDs.
While many LV customers are predicted to increase their annual usage requirements through
2030, their peak day requirements are not projected to grow by a similar rate of increase. This
is due in part to their increased use of extended work schedules, adding additional daily shifts
or adding production in weeks or months not previously utilized at 100% load factor (i.e.,
seasonal increases) and to the fact that customers often take time to "grow" past an existing
CD. Therefore, a certain pattern of therm use will not necessarily equate with a commensurate
level of growth in CD.
2.4.5 "Load Profile" vs MDFQ
Even though a monthly therm usage projection (i.e., load profile) is available for each customer,
the IRP optimization model does not use the load profile for modeling purposes. The model
instead uses the LV CDs because, as explained above, the LV customer group is not significantly
weather sensitive so attempting to estimate daily usage using degree days, as is done for the
core market, does not provide acceptable results. And without weather as the driver, it is
Page 33

difficult to estimate daily usage patterns. For these reasons using the customer CD as the daily
requirement is methodologically appropriate, as it reflects the known peak day obligation for
every customer and each Area of Interest (AOI). Most importantly, since Intermountain does
not provide gas supply or interstate pipeline capacity for any of the transportation customers,
the model does not need to project gas supply requirements for these customers, only the
maximum amount of distribution capacity they will need on any given day; customer CDs
provide this data.
Once the CDs are final, they are loaded directly into the optimization model by AOI and period.
The optimization model also assumes that transport customers deliver an amount of zero cost
gas supply equal to their aggregated CD for each transport rate class by AOI and period. That
assumption allows the model to recognize that gas supply and/or interstate capacity
requirements for the transport customers needs to be delivered each day but because it is not
provided by Intermountain, there is no need to attempt to calculate an unknown cost that is
not relevant to Intermountain.
2.4.6 System Reliability
Of import, before adding new firm load, engineers test the system via Intermountain's
modeling system to determine whether or not the Company could serve that added load under
design weather peak day loads before proceeding. This analysis is always completed prior to
executing any firm contract for any new customer or an existing customer's expansion. Since
the Company knows the various parts of the system that may be at or nearing constraints,
those AOI's are given particular attention under load growth scenarios. This procedure assures
current firm customers that new customers are not negatively affecting peak day deliverability.
2.4.7 General Assumptions
All current customers were assumed to remain on their current tariff and all forecast scenarios
used the 2024 operating budget as a starting point. The model also calculated LV therm use and
MDFQ by AOI so that each geographic area of concern can be accurately determined.
2.4.8 Base Case Scenario Summary
The Base Case was compiled using historical usage with adjustments made to reflect known or
probable changes of existing customers. The projected annual usage in the Base Case forecast
increased by 40 million therms (or an annualized rate of 2.0%) as seen in the table below.The
rate of projected annualized growth is largely driven by a significant expansion by one of the
Company's manufacturing customers.
Page 34

Large Volume Therm Forecast-Base Case by Market Segment
(Thousandsof Therms)
Rate of
2025 2026 2027 2028 2029 2030 Growth
Potato(A) 106,320 106,651 106,651 106,651 106,651 106,651 0.1%
Other Food (B) 124,828 124,697 125,497 125,497 125,497 125,497 0.1%
Meat,Dairy and Ag(C) 64,822 64,839 65,193 66,340 66,491 66,646 0.6%
Chemical/Fertilizer(D) 31,325 32,141 32,141 32,141 32,141 32,141 0.5%
Manufacturing(E) 26,278 38,954 46,026 52,003 54,136 57,618 17.0%
Institutional (F) 24,097 24,581 24,581 24,581 26,249 27,850 2.9%
Other(G) 16.417 17,819 17.819 18,319 18,319 18,319 2.2%
Total Base Case 394 087 409,682 417 908 425.532 429,484 434,722 2 0°i6
Table 4:Large Volume Therm Forecast-Base Case Scenario
A. The Potato Processors group is projected to see minimal growth over the forecast
period. No new plants are assumed in the forecast. Most of the plants in this group are
looking for ways to lower the overall cost of production, conserve resources and
maximize efficiencies leading to the flat projected usage for most customers.
B. The Other Food Processing group is also projected to see minimal growth over the
forecast period.
C. The Meat, Dairy and Ag segment is projected to see growth which largely reflects the
ramp up of two new plants in the forecast.
D. The Chemical/Fertilizer production segment usage is expected to remain relatively flat
over the forecast period.
E. The Manufacturing segment is seeing significant usage growth, which is due to a very
large planned expansion by one of the customers in this group.
F. The Institutional group is projected to have relatively flat growth, with a small amount
of growth due to a planned customer expansion towards the end of the IRP period.
G. The usage in the Other group is projected to see minor growth as customers ramp up
who use natural gas as part of their process to produce renewable natural gas.
Page 35

2.4.9 High Growth Forecast Summary
The High Growth forecast incorporates adjustments for additional growth that would occur if
inflation trends at a lower rate than that recently experienced and the economy starts to see
growth. The scenario assumes very competitive natural gas prices compared to other
alternatives. The Company forecasts projected sales in 2026 as flat to the base case scenario,
however by year 2028, the high case scenario is 1.2% above Base Case. The following table
summarizes the High Growth changes over the forecast period:
Large Volume Therm Forecast-High Growth by Market Segment
(Thousandsof Therms)
Rate of
2025 2026 2027 2028 2029 2030 Growth
Potato(A) 106,320 106,651 106,651 106,651 106,651 106.651 0.1%
Other Food (B) 124.828 124,697 126,947 126,947 126,947 126 947 0.3%
Meat, Dairy and Ag (C) 64,822 64,839 65,193 68,840 68,991 69.146 1.3%
Chemical/Fertilizer(D) 31,325 32,141 32,141 32,141 32,141 32.141 0.5%
Manufacturing (E) 26,278 38,954 46,026 52,003 54,136 57.618 17.0%
Institutional (F) 24,097 24,581 24,581 24,831 26,499 28.100 3.1%
Other(G) 16,417 17,819 19,319 19,319 19,319 19.319 3.3%
Total Base Case 394.087 409,682 4K858 430,732 434,684 439.922 21%
Table S:Large Volume Therm Forecast-High Growth Scenario
A. The Potato Processors group is projected to see no growth increase over the forecast
period. No new plants are assumed in this forecast. In this scenario, natural gas prices
are predicted to stay competitive and steady which would keep the plants using gas
rather than other energy sources.
B. The other Food Processors segment is forecasted to bring on 2 facilities beginning in
2027 as demand for sugar, frozen foods and other vegetables continues to increase.
C. The Meat, Dairy and Ag group is projected to show strong growth as existing facilities
expand and additional new meat producers ramp up. Two new dairy processors are
part of this high growth forecast period.
D. The Chemical/Fertilizer group is anticipated to see a minimal increase over the five-year
period.
E. The Manufacturing group is projected to see significant growth over the forecast period,
again as a result of a planned existing customer expansion. This scenario also assumes
the addition of one manufacturing related facility.
Page 36

F. The institutional group is expected to slightly grow over the five-year period as some
growth is projected in a few of the larger universities and several hospitals and one
hospital is built into the forecast.
G. Growth is expected to be strong in the Other segment as the increase for traditional
natural gas is being used in the production of renewable natural gas. Two producers are
coming online and two more are built into the forecast.
2.4.10 Low Growth Forecast Summary
The projected usage for this scenario is based upon the assumption that the economy enters a
long-term stall due to inflation or recession. Natural gas prices are also assumed to be less
competitive and other renewable sources begin to increase market share vis-a-vis natural gas.
With those assumptions, the potato, other food and institutional segments of the economy will
be flat with very little growth in sales and production. Intermountain reduced usage projections
for the Other Food segment assuming a potential shut down of one large plant. Manufacturing
shows growth because of an expansion that is currently underway. The Other segment is
expected to stay flat as the renewable fuels market declines and compressed natural gas (CNG)
markets are replaced by electric vehicles (EVs). Projected sales in year 2026 of the Low Growth
Scenario are approximately 7.3% below the Base Case but by 2030 the projected sales are 32.9
million therms (8.6%) under Base Case. The following table summarizes the Low Growth
changes over the forecast period:
Large Volume Therm Forecast-Low Growth by Market Segment
(Thousands of Therms)
Rate of
2025 2026 2027 2028 2029 2030 Growth
Potato(A) 106,320 106,651 106,651 106,651 106,651 106,651 0 1',C,
Other Food (B) 124,828 94,697 94,697 94.697 94,697 94,697 -5.4%o
Meat, Dairy and Ag (C) 64,822 64,839 65,049 65,049 65,049 65,049 0.1%
Chemical/Fertilizer(D) 31,325 32,141 32,141 32.141 32,141 32,141 0.5%
Manufacturing(E) 26,278 38,954 46,026 52,003 54,136 57,618 17.0%
Institutional (F) 24,097 24,581 24,581 24 581 26,249 27,850 2.9%
Other(G) 16,417 17,819 17,819 17.819 17,819 17,819 13%
Total Base Case 394.087 379.682 386.964 392 941 396,742 401 825 0A%
Table 6:Large Volume Therm Forecast-Low Growth Scenario
Page 37

A. The price of natural gas is assumed to be less competitive against the delivered price of
oil and other energy sources and overall market demand is expected to decline. This
group, as a whole, looks at any way possible to conserve energy and make its plants
more efficient.
B. In the Other Food Processor group the Company assumed one plant shutdown, resulting
in reduced volumes. Existing facilities will remain flat.
C. The Meat and Dairy group is projected to see only a slight increase over the period as
demand for meat and dairy is expected to remain steady.
D. The Chemical/Fertilizer segment is forecast with a very small increase in gas usage.
E. The Manufacturing group will see large growth due to the already in process massive
plant expansion, which will result in an increase over the period of 47%.
F. The institutional group is projected to show very minimal growth until 2029 when there
is a planned facility expansion that will increase annual gas usage.
G. The Other group is projected to see flat usage. No new renewable natural gas facilities
are forecasted to come on.
Page 38

3. Supply & Delivery Resources Overview
3.1 Overview
Once future load requirements have been forecasted, currently available supply and delivery
resources are matched with demand to identify system deficits. Essential components
considered when reviewing supply and delivery resources include identifying currently available
supply resources, delivery capacity, and other resources that can offset demand such as energy
efficiency programs or large volume customers with alternative fuel sources.
Supply and deliverability are considered by AOI to identify system constraints that result from
forecasted demand. By comparing demand versus capacity for each AOI,the Company is better
able to select capacity constraint solutions that consider cost effectiveness, operations and
maintenance impacts, project viability, and future growth.
After analyzing resource requirements for each AOI, the data is aggregated to provide a total
company perspective. Supply and delivery resources that are currently available are compared
to the six total company demand scenarios that were established in the demand forecast. In the
Load Demand Curves Section, demand and capacity are compared to clearly identify deficits.
Alternative solutions for how the deliverability deficits will be resolved are considered in the
Optimization and Planning Results sections of this Integrated Resource Plan.
Page 39

3.2 Traditional Supply Resources
3.2.1 Overview
Natural gas is a fundamental fuel for Idaho's economic and environmental future: heating homes,
powering businesses, moving vehicles, and serving as a key component in many of the most vital
industrial processes. The natural gas marketplace continues to change but Intermountain's
commitment to act with integrity to provide secure, reliable and price- competitive firm natural
gas delivery to its customers has not. In today's energy environment, Intermountain bears the
responsibility to structure and manage a gas supply and delivery portfolio that will effectively,
efficiently, reliably and with best value meet its customers' year- round energy needs. Through
its long-term planning, Intermountain continues to identify, evaluate and employ best-practice
strategies as it builds a portfolio of resources that will provide the value of service that its
customers expect.
The Traditional Supply Resources section outlines the energy molecule and related infrastructure
resources upstream of Intermountain's distribution system necessary to deliver natural gas to
the Company's distribution system. Specifically included in this discussion is the natural gas
commodity (or the gas molecule), various types of storage facilities, and interstate gas
transportation pipeline capacity. This section will identify and discuss the supply, storage, and
transportation capacity resources available to Intermountain and how they may be employed in
the Company's portfolio approach to gas delivery management.
3.2.2 Background
The procurement and distribution of natural gas is in concept a straightforward process. It simply
follows the movement of gas from its source through processing, gathering and pipeline systems
to end-use facilities where the gas is ultimately ignited and converted into thermal energy.
Natural gas is a fossil fuel; a naturally occurring mixture of combustible gases, principally
methane, found in porous geologic formations beneath the surface of the earth. It is produced
or extracted by drilling into those underground formations or reservoirs and then moving the gas
through gathering systems and pipelines to customers in often far away locations.
Intermountain is fortunate to be located between two prolific gas producing regions in North
America. The first, the Western Canadian Sedimentary Basin (WCSB) in Alberta and British
Columbia traditionally supplies approximately 79% of Intermountain's natural gas portfolio. The
other region, known as the Rockies, includes many different producing basins in the states of
Wyoming, Colorado, and Utah where the remainder of the Company's supplies are sourced. The
Company also utilizes storage facilities to store natural gas supply during the summer when prices
are traditionally lower and save it for use during the winter to offset higher seasonal pricing.
Page 40

Intermountain's access to the gas produced in these basins is wholly dependent upon the
availability of pipeline transportation capacity to move gas from those supply basins to
Intermountain's distribution system. The Company is fortunate, in that the interstate pipeline
that runs through Intermountain's service territory is a bi-directional pipeline. This means it can
bring gas from the north or south. Having the bi-directional flow capability allows
Intermountain's customers to benefit from the least cost gas pricing in most situations and ample
capacity to transport natural gas to Intermountain's citygates.
3.2.3 Gas Supply Resource Options
Since approximately 2008, advances in technology have allowed for the discovery and
development of abundant supplies of natural gas within shale plays across the United States and
Canada.This shale gas revolution has changed the energy landscape in the United States. Natural
gas production levels continue to surpass expectations despite low gas prices (see Figure 20
below).
Monthly U.S. dry shale natural gas production by formation
billion cubic feet per day
100
90 Permian
80
70 Haynesville
60 Marcellus
Utica
50 Eagle Ford
4 __ Bakken
0
Barnett
30
20 Mississippian
10 - Woodford
Rest of U.S.
2008 2010 2012 2014 2016 2018 2020 2022 2024
Data source: U.S. Energy Information Administration, Short-Term Energy Outlook, October 2025 e" dal
Figure 20:Natural Gas Sources
Page 41

Projected low prices for natural gas have made it a very attractive fuel for natural gas fired electric
generation as utilities are replacing coal-fired generation. Combine this with the industrial
sector's recovery from the 2007-2009 recession as they take advantage of low natural gas prices,
and the result is a significant change in demand loads. See Figure 21 below for consumption by
sector, 2000-2050.
Energy Use
quads
Ca40e: Reference case I Region: United States
30
20
10 —
0
-1
2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2046 2048 2050
— Residential: Natural Gas — Commercial: Natural Gas — Industrial: Natural Gas
Transportation: Liquefaction — Delivered:All Sectors: Natural Gas — Electric Power: Natural Gas
Total: Natural Gas
ei l Data source: U.S. Energy Information Administration
Figure 21:Natural Gas Consumption by Sector
Improved technologies for finding and producing nonconventional gas supplies have led to
dramatic increases in gas supplies. Figure 22 below shows that shale gas production is not only
replacing declines in other sources but is projected to increase total annual production levels to
the early 2030's and then flatting out through 2050.
Page 42

Total Energy: Production
goads
Case: Reference case
60
40 — — `— — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — -
20
z - — — — — — — — — — — — i s — — — — A
-2
2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2046 2048 2050
— Crude Oil and Lease Condensate — Natural Gas Plant Liquids — Dry Natural Gas Coal
— Nuclear — Hydropower Biomass Other Renewable Energy
eia Data source: U.S. Energy Information Administration
Figure 22: Shale Gas Production Trend
While natural gas prices continue to exhibit volatility from national, global, and regional
perspectives,the laws of supply and demand clearly govern the availability and pricing of natural
gas. Recent history shows that periods of growing demand tends to drive prices up which in turn
generally results in consumers seeking to lower consumption. At the same time, producers
typically increase investment in activities that will further enhance production. Thus, falling
demand coupled with increasing supplies tends to swing prices lower. This in turn leads to falling
supplies and increased demand which begins the cycle anew (see Figure 21 for shifting demand).
Finding equilibrium in the market has been challenging for all market participants but at the end
of the day,the competitive market clearly works;the challenge is avoiding huge swings that result
in either demand destruction or financial distress in the exploration and production business.
Driven by technological breakthroughs in unconventional gas production, major increases in
North American natural gas reserves and production have led to supply growth significantly
outgaining forecasts in recent years.Thus, natural gas producers have sought new and additional
sources of demand for the newfound volumes. The abundant supply of natural gas discussed
above has resulted in the United States becoming a net exporter of liquefied natural gas (LNG)
versus being a net importer several years ago. The currently operational LNG export facilities in
the United States together with additional new facilities on the drawing board will result in a
significant new market for the incremental gas supplies being developed and produced.
Page 43

3.2.4 Shale Gas
Shale gas has changed the face of U.S. energy. Today, reserve and production forecasts predict
ample and growing gas supplies through 2050 because of shale gas. The fact that shale gas is
being produced in the mid-section of the U.S has displaced production from more traditional
supply basins in Canada and the Gulf Coast. There have been some perceived environmental
issues relating to shale production, but most studies indicate that if done properly, shale gas can
be produced safely. Customers now enjoy the lowest natural gas prices in years due to the
increased production of shale gas. Figure 23 below identifies the shale plays in the lower 48
states.
Lower 48 states shale plays r ��
....Mmlana
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Prospective play weslem. o�
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Mixed shale&chalk play
Mixed shale&limestone play r, •�' �
Mixed shale&dolostone-siltstone-sandstone play �1
Mixed shale&limestonesiltstone-sandstone play Source:U.S.Energy.InfonrIn Admnletrason based on data from various published studies- la
r Updated:June 2018:
Figure 23: US Lower 48 States Shale Plays
Source: Energy Information Administration based on data from various published studies.
The COVID-19 pandemic had a profound and immediate impact on U.S. energy consumption. In
2020, total delivered energy demand across the residential, commercial, transportation, and
industrial sectors fell to approximately 90%of 2019 levels, a sharper decline than the drop in real
GDP.This contraction was roughly 70% larger than the decline observed during the 2008 financial
crisis.
Page 44

Initial projections from the U.S. Energy Information Administration (EIA), such as those in the
Annual Energy Outlook 2021 (AE02021), suggested that energy demand would not return to pre-
pandemic levels until 2029. However, more recent data indicates a faster-than-expected
recovery. By 2025, most sectors had rebounded to near-2019 consumption levels, with
transportation and industrial activity driving the resurgence.
• Residential and Commercial Sectors:These sectors stabilized earlier than expected, aided
by persistent remote work patterns and weather-normalized heating and cooling loads.
• Transportation Sector: After lagging through 2022, transportation fuel demand surged in
2023-2024, with vehicle miles traveled and jet fuel consumption approaching pre-
pandemic norms.
• Industrial Sector: Energy use rebounded alongside economic growth, particularly in
manufacturing-intensive regions.
• Electricity Demand: Grid-level demand normalized by 2023, although regional patterns
shifted during mitigation efforts.
Intermountain's demand forecasting models incorporate these updated recovery trends to
ensure that post-pandemic consumption patterns are accurately reflected in long-term planning.
The Company continues to monitor EIA projections and other market indicators to refine its
assumptions and ensure defensibility across planning horizons.
3.2.5 Supply Regions
As previously stated, Intermountain's natural gas supplies are obtained primarily from the WCSB
and the Rockies. Access to those abundant supplies is completely dependent upon the amount
of firm transportation capacity held on the applicable pipelines for delivering such gas to
Intermountain's service territory.Transportation capacity is so important that a discussion of the
Company's purchases of natural gas cannot be fully explored without also addressing pipeline
capacity. On average, Intermountain currently purchases approximately 79% of its gas supplies
from the WCSB and the remainder from the Rockies. However, due to certain flexibility in
Intermountain's firm transportation portfolio, it is afforded the opportunity to procure some
portion of its annual needs from supply basins which may offer lower cost gas supplies in the
future.
Page 45

Alberta
Alberta supplies are delivered to Intermountain via two Canadian pipelines(TransCanada Energy
via NOVA Gas Transmission Ltd. (NGTL) and Foothills Pipe Lines Ltd. (Foothills)) and two U.S.
pipelines (Gas Transmission Northwest (GTN) and Williams Northwest Pipeline (NWP)) as seen
below in Figure 24.
Heft-
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Jbi
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-� C—k-Kx —1 Gas
r—�Gas
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Figure 24: Supply Pipeline Map
Source:Northwest Gas Association 2024 Gas Market Outlook
Intermountain will continue to utilize a significant amount of Alberta supplies in its portfolio.The
Stanfield interconnect between NWP and GTN offers operational reliability and flexibility over
other receipts points both north and south. Where these supplies once amounted to a minor
portion of the Company's portfolio, today's purchases amount to approximately 76% of the
Company's annual purchases.
Page 46

British Columbia
British Columbia has traditionally been a source of competitively priced and abundant gas
supplies for the Pacific Northwest. Gas supplies produced in the province are transported by
Enbridge (Westcoast) to an interconnect with NWP near Sumas, WA. Historically, much of the
provincial supply had been somewhat captive to the region due to the lack of alternative pipeline
options into eastern Canada or the midwestern U.S. However, pipeline expansions into these
regions have eliminated that bottleneck. Although these supplies must be transported long
distances in Canada and over an international border,there have historically been few political or
operational constraints to impede ultimate delivery to Intermountain's citygates. An exception
to pipeline constraints occurred during the winter of 2018 when Enbridge had a major disruption
from a pipeline rupture that occurred on October 9, 2018. The ensuing winter months saw a
reduction in capacity in British Columbia gas supplies to be delivered at Sumas due to the incident
and pipeline integrity testing required by the Canada Energy Regulator' in Canada to ensure
safe and reliable pipeline conditions. Those interruptions along with a cold and long winter had
a significant impact on pricing. However, due to the predominance of Intermountain's supplies
coming from Alberta and being delivered via GTN at Stanfield, coupled with Intermountain's
ability to utilize its liquefied natural gas storage contracts on NWP's system,it was able to mitigate
the impact to its customers of the dramatic short-term price increases.
Rockies
Rockies supply has been the second largest source of supply for Intermountain because of the
ever-growing reserves and production from the region coupled with firm pipeline capacity
available to Intermountain. Additionally, Rockies supplies have been readily available and highly
reliable. Historically, pipeline capacity to move Rockies supplies out of the region has been
limited, which has forced producers to compete to sell their supplies to markets with firm
pipeline takeaway capacity. Several pipeline expansions out of the Rockies have greatly
minimized or eliminated most of the capacity bottlenecks, so these supplies can now more easily
move to higher priced markets found in the Midwest, East or in California. Consequently, even
though growth in Rockies reserves and production continues at a rapid pace reflecting increased
success in finding tight sand, coal seam and shale gas, the more efficient pipeline system has
largely eliminated the price advantage that Pacific Northwest markets had enjoyed.
While Intermountain's firm transportation portfolio does provide for accessing Rockies gas
supplies, as discussed above, Intermountain has prioritized purchasing its annual supply needs
predominantly out of Alberta due to the lower cost environment from that supply basin.
The Canada Energy Regulator (CER) is the agency of the Government of Canada under its Natural
Resources Canada portfolio, which licenses, supervises, regulates, and enforces all applicable Canadian
laws as regards to interprovincial and international oil, gas, and electric utilities. The agency came into
being on August 28, 2019, under the provision of the Canada Energy Regulator Act of the Parliament of
Canada superseding the National Energy Board from which it took over responsibilities.
Page 47

However, due to its close proximity, Intermountain does purchase the lower cost Rockies gas
supplies in the summer for injection into its Clay Basin storage accounts located in northeastern
Utah.
3.2.6 Export LNG
Growth in North American natural gas supplies (see Shale Gas above) has eliminated discussion
about LNG import facilities. Because LNG is traded on the global market, where prices are
typically tied to oil, U.S. produced LNG is very competitive. LNG exports now play a role in the
overall supply portfolio of U.S. supply, with several new LNG export facilities proposed or in
production. As seen in Figure 25 below,the U.S. is now a net exporter of natural gas in large part
due to LNG.
U.S. dry natural gas production and liquefied natural gas (LNG) exports (2010-2050)
trillion cubic feet @I,
production LNG exports
60 2022 High Oil 16 2022 High Oil
history projections Price history projections Price
50 i High Oil and 14
Gas Supply ' High Oil and
12
Gas Supply
40 Reference
Low Oil 10 Reference
30 Price 8
Low Oil and
Gas Supply 6 Low Oil and
20 Gas Supply
4 Low Oil
10 2 Price
0 0
2010 2020 2030 2040 2050 2010 2020 2030 2040 2050
Figure 25: Natural Gas Sources
Source: U.S. Energy Information Administration, Annual EneLU Outlook 2023 (AE02023)
3.2.7 Types of Supply
There are essentially two main types of gas supply: firm and interruptible. Firm gas commits the
seller to make the contracted amount of gas available each day during the term of the contract
and commits the buyer to take that gas each day. The only exception would be force majeure
events where one or both parties cannot control external events that make delivery or receipt
impossible. Interruptible or best-efforts gas supply typically is bought and sold with the
understanding that either party,for various reasons, does not have a firm or binding commitment
to take or deliver the gas.
Page 48

Intermountain builds its supply portfolio on a base of firm, long-term gas supply contracts but
includes all the types of gas supplies as described below:
1. Long-term: gas that is contracted for a period of over one year.
2. Short-term: gas that is often contracted for one month at a time.
3. Spot: gas that is not under a long-term contract; it is generally purchased in the short-
term on a day ahead basis for day gas and during bid week prior to the beginning of the
month for monthly spot gas.
4. Winter Baseload:gas supplythat is purchased fora multi-month period most often during
winter or peak load months.
5. Citygate Delivery: natural gas supply that is bundled with interstate transportation
capacity and delivered to the Intermountain citygate meaning that it does not use the
Company's existing transportation capacity.
3.2.8 Pricing
The Company does not currently utilize NYMEX based products to hedge forward prices but buys
a portion of its gas supply portfolio at fixed priced forward physicals. Purchasing fixed price
physicals provides the same price protection without the credit issues that come with financial
instruments. A certain level of fixed price contracts allows Intermountain to participate in the
competitive market while avoiding upside pricing exposure. While the Company does not utilize
a fully mechanistic approach, its Gas Supply Oversight Committee meets frequently to discuss all
gas portfolio issues which helps to provide stable and competitive prices for its customers.
For IRP purposes, the Company develops a base, high, and low natural gas price forecast.
Demand, oil price volatility, the global economy, electric generation, environmental policies,
opportunities to take advantage of new extraction technologies, hurricanes and other weather
activity will continue to impact natural gas prices for the foreseeable future. Intermountain
considers price forecasts from several sources, such as Wood Mackenzie, EIA,S&P Global, NYMEX
Henry Hub, and Northwest Power and Conservation Council, as well as Intermountain's own
observations of the market to develop the low, base, and high price forecasts. For optimization
purposes, Intermountain uses pricing forecasts from four sources for the AECO, Rockies and
Sumas pricing points along with a proprietary model based upon those forecasts. The selected
forecast includes a monthly base price projection for each of the three purchase points, as seen
in Figure 26.
Page 49

IGC Natural Gas Price Forecast (as of 5-7-2025)
$8.00
$7.00
$6.00
$5.00
m
$4.00
$3.00
$2.00
$1.00 - — —
$0.00
lac �a� �eQ sac �a� �eQ lac �aJ yeQ �a� �a� yeQ sac �aJ yeQ
-Sumas Rockies AECO Weighted
Figure 26:Intermountain Price Forecast as of 0510712025
3.2.9 Storage Resources
The production of natural gas and the amount of available pipeline capacity are very linear in
nature; changes in temperatures or market demand does not materially affect how much of
either is available daily. As the Resource Optimization Section discusses, a peak day only occurs
for, at most, a few days out of the year. The demand curve then drops rapidly back to more
normal winter supply levels before dropping off drastically headed into the summer months.
Attempting to serve the entire year at levels required to meet peak demand would be
enormously expensive. So,the ability to store natural gas during periods of non-peak demand for
use during peak periods is a cost-effective way to fill the gap between static levels of supply and
capacity versus the non-linear demand curve.
Intermountain utilizes storage capacity in four different facilities from western Washington to
northeastern Utah. Two are operated by NWP: one is an underground project located near
Jackson Prairie, WA (JP) and the other is a liquefied gas (LS) facility located near Plymouth, WA
(see Figure 27 below). Intermountain also leases capacity from Dominion Energy Pipeline's Clay
Basin underground storage field in Wyoming, and operates its own LNG facility located in Nampa,
ID. Additionally, Intermountain owns a satellite LNG facility in Rexburg, ID. The Rexburg facility is
supplied with LNG from the Nampa LNG facility.
Page 50

All storage resources allow Intermountain to inject gas into storage during off-peak periods and
then hold it for withdrawal whenever the need arises. The advantage is three-fold: 1) the
Company can serve the extreme winter peak while minimizing year-round firm gas supplies; 2)
storage allows the Company to minimize the amount of the year-round interstate capacity
resources required and helps it to use existing capacity more efficiently; and 3) storage provides
a natural price hedge against the typically higher winter gas prices. Thus, storage allows the
Company to meet its winter loads more efficiently and in a cost-effective manner.
�•,••�: NdW Gay&v0%Am=
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Figure 27:Intermountain Storage Facilities
Page 51

Liquefied Storage
Liquefied storage facilities make use of a process that super cools and liquefies gaseous methane
under pressure until it reaches approximately minus 260°F. LNG occupies only one-six-hundredth
the volume compared to its gaseous state, so it is an efficient method for storing peak
requirements. LNG is also non-toxic; it is non-corrosive and will only burn when vaporized to a 5-
15%concentration with air. Because of the characteristics of liquid, its natural propensity to boil-
off and the enormous amount of energy stored, LNG is normally stored in man-made steel tanks.
Liquefying natural gas is, relatively-speaking, a time-consuming process, the compression and
storage equipment is costly, and liquefaction requires large amounts of added energy. It typically
requires as much as one unit of natural gas burned as fuel for every three to four units liquefied.
Also, a full liquefaction cycle may take five to six months to complete. Because of the high cost
and length of time involved in filling a typical LNG facility, they are usually cycled only once per
year and are reserved for peaking purposes. This makes the unit cost of the gas withdrawn
somewhat expensive when compared to other options.
Vaporization,or the process of changing the liquid back into the gaseous state,on the other hand,
is a very efficient process. Under typical atmospheric and temperature conditions, the natural
state of methane is gaseous and lighter than air as opposed to the dense state in its liquid form.
Consequently, vaporization requires little energy and can happen very quickly. Vaporization of
LNG is usually accomplished by utilizing pressure differentials by opening and closing valves in
concert with the use of some hot-water bath units. The high-pressure LNG is vaporized as it is
warmed and is then allowed to push itself into the lower pressure distribution system. Potential
LNG daily withdrawal rates are normally large and, as opposed to the long liquefaction cycle, a
typical full withdrawal cycle may last 10 days or less at full rate. Because of the cost and cycle
characteristics, LNG withdrawals are typically reserved for needle peaking during very cold
weather events or for system integrity events.
Neither of the two LNG facilities utilized by Intermountain require the use of year-round
transportation capacity for delivery of withdrawals to Intermountain's customers. The Plymouth
facility is bundled with redelivery capacity for delivery to Intermountain and the Nampa and
Rexburg LNG tank withdrawals go directly into the Company's distribution system. The IRP
assumes liquid storage will serve as a needle peak supply.
Underground Storage
This type of facility is typically found in naturally occurring underground reservoirs or aquifers
(e.g. depleted gas formations, salt domes, etc.) or sometimes in man-made caverns or mine
shafts. These facilities typically require less hardware compared to LNG projects and are usually
less expensive to build and operate than liquefaction storage facilities. In addition, commodity
costs of injections and withdrawals are usually minimal by comparison. The lower costs allow for
Page 52

the more frequent cycling of inventory and in fact, many such projects are utilized to arbitrage
variations in market prices.
Another material difference is the maximum level of injection and withdrawal. Because
underground storage involves far less compression as compared to LNG, maximum daily injection
levels are much higher, so a typical underground injection season is much shorter, typically
lasting only three to four months. But the lower pressures also mean that maximum withdrawals
are typically much less than liquefied storage at maximum withdrawal. So, it could take 35 days
or more to completely empty an underground facility.The longer withdrawal period and minimal
commodity costs make underground storage an ideal tool for winter baseload or daily load
balancing, and therefore, Intermountain normally uses underground storage before liquid
storage is withdrawn. Underground storage is not ideal for delivering a large amount of gas
quickly, however, so LNG is a better solution for satisfying a peak situation.
Intermountain contracts with two pipelines for underground storage: Dominion Energy for
capacity at its Clay Basin facility in northeastern Utah and NWP for capacity at its Jackson Prairie
facility in Washington. Clay Basin provides the Company with the largest amount of seasonal
storage and daily withdrawal. However, since Clay Basin is not bundled with redelivery capacity,
Intermountain must use its year-round capacity when these volumes are withdrawn. For this
reason, the Company normally uses Clay Basin withdrawals during the November to March
winter period to satisfy baseload needs.
Just like NWP's Plymouth LS facility, NWP's JP storage is bundled with redelivery capacity so
Intermountain typically layers JP withdrawals between Clay Basin and its LNG withdrawals. The
IRP uses Clay Basin as a winter baseload supply and JP is used as the first layer of peak supply.
Table 7 below outlines the Company's storage resources for this IRP.
Daily Withdrawal(Dth) Daily Injection(Dth)
Seasonal of2025 Redelivery
Facility Capacity Max Vol Peak Max Vol #of Days Capacity
Nampa 600.000 50.000 9% 3,500 166 None
Plymouth 1,475,135 155.175 29�.c 12,500 213 TF-2
Subtotal Liquid 2,075.135 205.175 39% 16,000
Jackson Prairie 1,092.099 30.337 6% 30.337 36 TF-2
Clay basin 8.413.500 70,114 1Y.5 70,114 120 TF-1
Subtotal Underground 9,505,599 100.451 19% 100,451
Grand Total 11.580.734 305.626 58% 116,451
Table 7: Storage Resources
Page 53

All the storage facilities require the use of Intermountain's every day, year-round capacity for
injection or liquefaction. Because injections usually occur during the summer months, use of
year-round capacity for injections helps the Company make more efficient use of its everyday
transport capacity and term gas supplies during those off-peak months when the core market
loads are lower.
Nampa LNG Plant
The primary purpose of the Nampa LNG plant is to supplement gas supply onto Intermountain
Gas' distribution system. The Nampa LNG plant can store up to 600 million cubic feet of natural
gas in liquid form and can re-gasify back into Intermountain's system at a rate of approximately
50 million cubic feet per day.
During a needle peak event the plant is able to supplement supply during gas storage shortages
or transportation restrictions into Idaho, and the plant has the added benefit of supplying natural
gas directly into the connected Canyon County and Ada County distribution systems without use
of interstate pipeline transportation, which eliminates another risk variable typically associated
with gas supply.The Nampa LNG plant typically performs liquefaction operations during non-peak
weather times of the year, resulting in lower priced natural gas going into liquid storage, and
providing potential cost savings when re-gasification occurs during peak cold weather events, gas
supply shortages and interstate transportation restrictions.
Storage Summary
The Company generally utilizes its diverse storage assets to offset winter load requirements,
provide peak load protection and, to a lesser extent, for system balancing. Intermountain
believes that the geographic and operational diversity of the four facilities utilized offers the
Company and its customers a level of efficiency, economics and security not otherwise
achievable. Geographic diversity provides security should pipeline capacity become constrained
in one particular area. The lower commodity costs and flexibility of underground storage allows
the Company flexibility to determine its best use compared to other supply alternatives such as
winter baseload or peak protection gas, price arbitrage or system balancing.
Page 54

3.2.10 Interstate Pipeline Transportation Capacity
As discussed earlier, Intermountain is dependent upon firm pipeline transportation capacity to
move natural gas from the areas where it is produced, to end-use customers who consume the
gas. In general, firm transportation capacity provides a mechanism whereby a pipeline will
reserve the right, on behalf of a designated and approved shipper,to receive a specified amount
of natural gas supply delivered bythat shipper, at designated receipt points on its pipeline system
and subsequently redeliver that volume to delivery point(s) as designated by the shipper.
Intermountain holds firm capacity on four different pipeline systems including NWP. NWP is the
only interstate pipeline which interconnects to Intermountain's distribution system, meaning
that Intermountain physically receives all gas supply to its distribution system (otherthan Nampa
LNG) via citygate taps with NWP. Table 8 below summarizes the Company's year-round capacity
on NWP (TF-1)and its storage specific redelivery capacity(TF-2). Between the amount of capacity
Intermountain holds on the GTN, Foothills, and NGTL pipelines and firm- purchase contracts at
Stanfield, it controls enough capacity to deliver a volume of gas commensurate with the
Company's Stanfield takeaway capacity on NWP. Upstream pipelines bring natural gas from the
production fields in Canada to the interconnect with NWP.
Page 55

City Gate Delivery Quantity 2025 2026 2027 2028 2029 2030
(MMBtu per day)
TF-1 Capacity-
Sumas Base Capacity 90,941 90,941 90,941 90,941 90,941 90,941
Sumas Segmentation and (90,941) (90,941) (90,941) (90,941) (90,941) (90,941)
Release
Sumas Winter Only Capacity 3,000 - - - - -
Stanfield Base Capacity 133,624 133,624 133,624 133,624 133,624 133,624
Stanfield Capacity Via
90,941 90,941 90,941 90,941 90,941 90,941
Segmentation
Rockies 59,328 59,328 59,328 59,328 59,328 59,328
Total TF-1 Capacity 286,893 283,893 283,893 283,893 283,893 283,893
City Gate Supply 10,000 10,000 10,000 10,000 10,000 10,000
Total City Gate Delivery
296,893 293,893 293,893 293,893 293,893 293,893
Before TF-2
TF-2 Capacity-
Plymouth (LS) 155,175 155,175 155,175 155,175 155,175 155,175
Jackson Prairie (JP) 30,337 30,337 30,337 30,337 30,337 30,337
Total TF-2 Capacity 185,512 185,512 185,512 185,512 185,512 155,175
Nampa and Rexburg LNG 55,500 55,500 55,500 55,500 55,500 55,500
Total City Gate Delivery 537,405 534,405 534,405 534,405 534,405 534,405
Table 8:Northwest Pipeline Transport Capacity
Page 56

Northwest Pipeline's facilities essentially run from the Four Corners area north to western
Wyoming, across southern Idaho to western Washington.The pipeline then continues up the 1-5
corridor where it interconnects with Spectra Energy, a Canadian pipeline in British Columbia, near
Sumas, Washington. The Sumas interconnect receives natural gas produced in British Columbia.
Gas supplies produced in the province of Alberta are delivered to NWP via NOVA, Foothills and
then GTN near Stanfield, Oregon. NWP also connects with other U.S. pipelines and gathering
systems in several western U.S. states (Rockies) where it receives gas produced in basins located
in Wyoming, Utah, Colorado, and New Mexico. The major pipelines in the Pacific Northwest,
several of which NWP interconnects with can be seen below (Figure 28).
f / Western
Canadian
Station 2 «dlnwntJry
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Foot�lb
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Figure 28:Map-Pacific Northwest Pipelines
Page 57

Because natural gas must flow along pipelines with finite flow capabilities, demand frequently
cannot be met from a market's preferred basin. Competition among markets for these preferred
gas supplies can cause capacity bottlenecks and these bottlenecks often result in pricing
variations between basins supplying the same market area. In the short to medium term,
producers in constrained basins invariably must either discount or in some fashion differentiate
their product to compete with other also constrained supplies. In the longer run however,
disproportionate regional pricing encourages capacity enhancements on the interstate pipeline
grid, from producing areas with excess supply, to markets with constrained delivery capacity.
Such added capacity nearly always results in a more integrated, efficient delivery system that
tends to eliminate or at least minimize such price variances.
Consequently, new pipeline capacity- or expansion of existing infrastructure— in western North
America has increased take-away capacity out of the WCSB and the Rockies, providing producers
with access to higher priced markets in the East, Midwest and in California. Therefore, less-
expensive gas supplies once captive to the northwest region of the continent, now have greater
access to the national market resulting in less favorable price differentials for the Pacific
Northwest market. Today, wholesale prices at the major trading points supplying the Pacific
Northwest region (other than Alberta supplies) are trending towards equilibrium. At the same
time, new shale gas production in the mid-continent is beginning to displace traditionally higher-
priced supplies from the Gulf coast which, from a national perspective, has been causing an
overall softening trend in natural gas prices with less regional differentials.
Today, Intermountain and the Pacific Northwest operate within an increasingly interconnected
mega-regional marketplace, where market conditions across North America, including pipeline
capacity constraints, LNG export dynamics, and storage levels, continue to influence regional
supply availability and pricing. According to the U.S. Energy Information Administration (EIA),
Henry Hub natural gas prices are projected to average $3.50 per MMBtu in 2025, nearly double
the 2024 average, due to early-year cold weather events that depleted Lower 48 storage
inventories.2 Despite net injections beginning in March, inventories remain below recent norms,
contributing to upward price pressure. At the same time, strong global demand for U.S. liquefied
natural gas (LNG) and sustained domestic consumption for electric power generation have
limited downward movement in prices.' These factors underscore the importance of flexible
procurement strategies and diversified supply portfolios to mitigate volatility in Intermountain's
planning horizon.
2 See:https://www.eia.gov/outlooks/steo/pdf/steo full.pdf
3 See:EIA expects higher wholesale U.S.natural gas prices as demand increases-U.S.Energy Information Administration(EIA)
Page 58

3.2.11 Supply Resources Summary
Because of the dynamic environment in which it operates,the Company will continue to evaluate
customer demand to provide an efficient mix of supply resources to meet its goal of providing
reliable, secure, and economic firm service to its customers. Intermountain actively manages its
supply and delivery portfolio and consistently seeks additional resources where needed. The
Company actively monitors natural gas pricing and production trends to maintain a secure,
reliable and price competitive portfolio and seeks innovative techniques to manage its
transportation and storage assets to provide both economic benefits to customers and
operational efficiencies to its interstate and distribution assets. The IRP process culminates with
the optimization model that helps to ensure that the Company's strategies meet its traditional gas
supply goals and are based on sound, real-world, economic principles (see the Optimization
Section).
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3.3 Capacity Release & Mitigation Process
3.3.1 Overview
Capacity release was implemented by FERC to allow markets to more efficiently utilize pipeline
transportation and storage capacity. This mechanism allows a shipper with any such unused
capacity to auction the excess to another shipper that offers the highest bid. Thus, capacity that
would otherwise sit idle can be used by a replacement shipper. The result is a more efficient use
of capacity as replacement shippers maximize annualized use of existing capacity. One effect of
maximizing the utilization of existing capacity is that pipelines are less inclined to build new
capacity until the market recognizes that it is really needed and is willing to pay for new
infrastructure. However, a more fully utilized pipeline can also mean existing shippers have less
operational flexibility.
Intermountain has and continues to be active in the capacity release market. Intermountain
obtains significant amounts of unutilized capacity mitigation on NWP and GTN via capacity
releases. The Company frequently releases seasonal and/or daily capacity during periods of
reduced demand. Intermountain also utilizes a specific type of capacity release called
segmentation to convert capacity from Sumas to Idaho into two paths of Sumas to Stanfield and
Stanfield to Idaho. Intermountain uses the Stanfield to Idaho component to take delivery of the
lower cost AECO gas supplies that are delivered by GTN to the interconnect with NWP at
Stanfield. IGI Resources, Inc. (IGI) is then able to market the upper segment of Sumas to Stanfield
to other customers.
Capacity release has also resulted in a bundled service called citygate, in which gas marketers
bundle gas supplies with available capacity to be delivered directly to a market's gate station.
This grants additional flexibility to customers attempting to procure gas supplies for a specified
period (i.e. during a peak or winter period) by allowing the customer to avoid contracting for
year-round capacity which would not be used during off-peak periods.
Pursuant to the requirements under the Services Agreement between Intermountain and IGI, IGI
is obligated to generate the maximum cost mitigation possible on any unutilized firm
transportation capacity Intermountain has throughout the year. In performing this obligation,
IGI must also ensure that: 1) in no way will there be any degradation of firm service to
Intermountain's residential and commercial customers, and 2) that Intermountain always has
first call rights on any of its firm transportation capacity throughout the year and if necessary
Intermountain has the right to recall any previously released capacity if needed to meet core
market demands.
With the introduction of natural gas deregulation under FERC Order 436 in 1985 and the
subsequent FERC Orders 636, 712, 712A and 71213, the rules and regulations around capacity
release transactions for interstate pipeline capacity were developed. These rules cover such
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activity as: 1) shipper must have title; 2) prohibition against tying arrangements and 3) illegal
buy/sell transactions. These rules and regulations are very strict and must always be adhered to
or the shipper is subject to significant fines(up to$1 million per day per violation) if ever violated.
IGI is very aware of these regulations and at all times ensures adherence to such when looking
for replacement shippers of Intermountain's unutilized pipeline capacity.
The FERC jurisdiction of interstate pipelines for which Intermountain holds capacity are NWP and
GTN. To facilitate capacity release transactions, all pipelines have developed an Electronic
Bulletin Board (EBB) for which such transactions are to be posted. All released transportation
capacity must be posted to the applicable pipeline EBB and in a manner that allows a competing
party to bid on it.
3.3.2 Capacity Release Process
Because of its significant market presence in the Pacific Northwest, IGI has been able to generate
several millions of dollars per year in released capacity mitigation dollars on behalf of
Intermountain for pass-back to its core market customers and to reduce the cost of unutilized
firm transportation capacity rights. In this effort, IGI can determine what the appetite is in the
competitive marketplace for firm transportation releases on NWP and GTN. It does this via direct
communication with third parties or by market intelligence it receives from its marketing team
as it deals with its customers and other markets throughout the region. However, the most
effective way of determining interest in capacity releases is using the EBB. IGI performs its
obligation to Intermountain in one of two ways. First, if IGI itself is interested in utilizing any of
Intermountain's unutilized firm transportation capacity, it determines what it believes is a market
competitive offer for such and that is then posted to the EBB as a pre-arranged deal. As a pre-
arranged deal, the transaction remains on the EBB for the requisite time and any third party has
the opportunity to offer a higher bid. If this is done, then IGI can chose to match the higher bid
and retain the use of the capacity, or not to match and the capacity will be awarded to the higher
third-party bidder.
Second, if IGI is not interested in securing any unutilized Intermountain capacity then it will post
such capacity to the EBB as available and subject to open bidding by any third party. As such, the
unutilized capacity will be awarded to the highest bidder. It should be noted that IGI posts to the
EBB, as available capacity, certain volumes of capacity for certain periods every month during bid
week. This affords the most exposure to parties that may be interested in securing certain
capacity rights. However,to date,third parties have chosen to bid on such available capacity only
a handful of times over all these years.
It should also be noted, that to protect the availability of firm transportation to Intermountain's
residential and commercial customers during the year, all released capacity postings to the EBB,
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whether pre-arranged or not, are posted as recallable capacity. This means that Intermountain
can recall the capacity at any time, if necessary, to cover its customer demand.
3.3.3 Mitigation Process
IGI is also obligated to use its best efforts to mitigate the cost of transportation on the pipeline
facilities of Nova and Foothills when they are not being used by Intermountain for its own
needs. These pipelines are located in Canada and as such are not subject to the rules and
regulations of FERC Order 436, 636, 712(A) and 712(B). However, IGI uses much the same
evaluation methods for these Canadian pipelines as it does for NWP and GTN. IGI periodically
inquires with third parties as to any interest in potential unused capacity on Nova and Foothills
for certain periods of time known to be available. IGI also determines if it has any interest in
such available capacity for its use in serving other markets in the Pacific Northwest. There is no
EBB process on these Canadian pipelines. However, IGI employs much the same process as on
NWP and GTN to determine the best mitigation value for Intermountain. Also, similar to the
process on NWP and GTN, any of the unused NOVA and Foothills capacity used by IGI or other
third parties is always subject to recall should Intermountain have any need for that capacity to
serve its customers.
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3.4 Non-Traditional Supply Resources
Non-traditional supply resources help supplement the traditional supply-side resources during
peak demand conditions. Non-traditional resources consist of energy supplies not received from
an interstate pipeline supplier, producer or interstate storage operator. Seven non-traditional
supply resources were considered in this IRP and are as follows:
Non-Traditional Supply Resources
1. Diesel/Fuel Oil
2. Coal
3. Wood Chips
4. Propane
5. Satellite/Portable LNG Facilities
6. Renewable Natural Gas (RNG)
7. Hydrogen
While a large volume industrial customer's load profile is relatively flat compared to most
residential and commercial customers, the Company's industrial customers are still a significant
contributor to overall peak demand. However, some industrial customers have the ability to use
alternate fuel sources to temporarily reduce their reliance on natural gas. By using alternative
energy resources such as coal, propane, diesel and wood chips, an industrial customer can lower
their natural gas requirement during peak load periods while continuing to receive the energy
required for their specific process. Although these alternative resources and related equipment
typically have the ability to operate anytime during the year, most are ideally suited to run during
peak demand from a supply resource perspective. However, only the industrial market has the
ability to use any of the aforementioned alternate fuels in large enough volumes to make any
material difference in system demand. In order to rely on these types of peak supplies
Intermountain would need to engage in negotiations with specific customers to ensure
availability. The overall expense of these kinds of arrangements, if any, is difficult to assess.
The non-traditional resources of satellite/portable liquid natural gas (LNG) facilities and RNG do
not technically reduce system demand. However, LNG typically has the ability to provide
additional natural gas supply at favorable locations within a potentially constrained distribution
system. RNG and hydrogen production could potentially supply a distribution system in a similar
fashion, however, the location of such facilities, which are determined by the producer, may not
align with a constrained location of the distribution system, thus limiting their potential efficacy
as a non-traditional supply resource.
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3.4.1 Diesel/Fuel Oil
Intermountain is aware of two large volume customers along the IFL that currently have the
potential to use diesel or fuel oil as a natural gas supplement. The facilities are able to switch
their boilers over to burn oil and decrease a portion of their gas usage. Burning diesel or fuel oil
in lieu of natural gas requires permitting from the local governing agencies, increases the level of
emissions, and can have a lengthy approval process depending on the specific type of fuel oil
used. The cost of diesel or fuel oil varies depending on fuel grade and classification, time of
purchase and quantity of purchase.
3.4.2 Coal
Coal use is very limited as a non-traditional supply resource for firm industrial customers within
Intermountain's service territory. A coal user must have a separate coal burning boiler installed
along with their natural gas burning boilers and typically must have additional equipment
installed to transport the large quantities of coal within their facility. Regulations and permitting
requirements can also be a challenge. Intermountain is currently aware of only one industrial
customer on its system that has a coal backup system.
The cost of coal varies depending on the quality of the coal. Lower BTU coal would range from
8,000 — 13,000 BTU per pound while higher quality coal would range from 12,000 - 15,000 BTU
per pound.
3.4.3 Wood Chips
Historically Intermountain has had one large volume industrial customer on the IFL that had the
ability to utilize wood chips as an alternative fuel. However, after a recent expansion it is unclear
how much or often this customer utilizes this alternative fuel. In order to accommodate wood
burning there must be additional equipment installed, such as wood fired boilers, wood chip
transport and dry storage facilities. The wood is supplied from various tree clearing and wood
mill operations that produce chips within regulatory specifications to be used as fuel. The chips
are then transported by truck to the location where the customer could utilize them as a fuel
source for a few months each year.
The cost of wood is continually changing based on transportation, availability, location and the
type of wood processing plant that is providing the chips. Wood has a typical value of 5,000-6,000
BTU's per pound,which converts into 16-20 pounds of wood being burned to produce one therm
of natural gas.
Page 64

3.4.4 Propane
Since propane is similar to natural gas, the conversion to propane is much easier than a
conversion to most other non-traditional supply resources. With the equipment, orifices and
burners being similar to that of natural gas, an entire industrial customer load (boiler and direct
fire) may be switched to propane. Therefore, utilizing propane on peak demand could reduce an
industrial customer's natural gas needs by 100%. The use of propane requires onsite storage,
additional piping and a reliable supply of propane to maintain adequate storage. Currently there
are no industrial customers on Intermountain's system that have the ability to use propane as a
feasible alternative to natural gas.
Capital costs for propane facilities can become relatively high due to storage requirements. As
with oil, storage facilities should be designed to accommodate a peak day delivery load for
approximately seven (7) days. One gallon of propane is approximately 91,600 BTU.
3.4.5 Satellite/Portable LNG Equipment
Satellite/Portable LNG equipment allows natural gas to be transported in tanker trucks in a
cooled liquid form; meaning that larger BTU quantities can be delivered to key supply locations
that can support LNG deliveries. Liquefied natural gas has tremendous withdrawal capability
because the natural gas is in a denser state of matter. Portable equipment has the ability to boil
LNG back to a gaseous form and deliver it into the distribution system by heating the liquid from
-260 degree Fahrenheit to a typical temperature of 50 — 70 degree Fahrenheit. This portable
equipment is available to lease or purchase from various companies and can be used for peak
shaving at industrial plants or within a distribution system. Regulatory and environmental
approvals are minimal compared to permanent LNG production plants and are dependent upon
the specific location where the portable LNG equipment is placed.The available delivery pressure
from LNG equipment ranges from 150 psig to 650 psig with a typical flow capability of
approximately 2,000 - 8,000 therms per hour.
Intermountain Gas currently operates a portable LNG unit on the northern end of the Idaho Falls
Lateral to assist in peak shaving the system. In addition to the portable equipment, Intermountain
also has a permanent LNG facility on the IFL that is designed to accommodate the portable
equipment, provide an onsite control building and allow onsite LNG storage capabilities. The
ability to store LNG onsite allows Intermountain to partially mitigate the risk associated with
relying on truck deliveries during critical flow periods. The LNG delivery risk is also reduced now
that Intermountain has the ability to withdraw LNG from the Nampa LNG Storage Tank and can
transport this LNG across the state in a timely manner. With Nampa LNG readily available the
cost and dependence on third-party supply is removed.
Page 65

3.4.6 Renewable Natural Gas
RNG can be defined as utilizing any biomass material to produce a renewable fuel gas. Biomass
is any biodegradable organic material that can be derived from plants, animals, animal
byproduct, wastewater, food/production byproduct and municipal solid waste. After processing
of RNG to industry purity standards the gas can then be used within Company facilities.
Idaho is one of the nation's largest dairy producing states which make it a prime location for RNG
production utilizing the abundant supply of animal and farm byproducts. Southern Idaho
currently has four RNG producers on Intermountain's distribution system. All four producers
supply RNG from dairy operations and are located in the Twin Falls area. In addition to these
current producers, the Company is currently working with multiple prospective projects and
expects additional RNG producers to come onto Intermountain's distribution systems in coming
years.
Intermountain has included RNG as a potential resource to solve any supply shortfalls the
Company may have. RNG that has been cleaned to the Company's specifications can be used
interchangeably with traditional natural gas in Intermountain's pipelines and in the customers'
end use equipment. The Company estimated the price of RNG at current regional market rates
considering the limited selling opportunities for RNG producers.
3.4.7 Hydrogen
Hydrogen is a clean alternative to methane. "Hydrogen can be produced from various
conventional and renewable energy sources including as a responsive load on the electric grid.
Hydrogen has many current applications and many more potential applications, such as energy
for transportation—used directly in fuel cell electric vehicles (FCEVs), as a feedstock for
synthetic fuels, and to upgrade oil and biomass—feedstock for industry(e.g., for ammonia
production, metals refining, and other end uses), heat for industry and buildings, and electricity
storage. Owing to its flexibility and fungibility, a hydrogen intermediate could link energy
sources that have surplus availability to markets that require energy or chemical feedstocks,
benefiting both."1 Hydrogen can be produced by a variety of sources that are delineated by
colors:
• Blue hydrogen: Hydrogen produced using natural gas to create steam while capturing
CO2;
• Green hydrogen: Hydrogen produced through electricity from renewables;
• Brown hydrogen: Hydrogen produced by coal;
• Pink hydrogen: Hydrogen produced through electricity from nuclear reactors; and
https://www.nrel.gov/docs/fy2losti/77610.pdf
Page 66

• Gray hydrogen: Hydrogen produced using natural gas to create steam without capturing
CO2;
"The coalition estimated that the levelized cost of green hydrogen could reach $2.05 per kilogram
in 2030,even without government incentives. By factoring in the production tax credit authorized
by the US Inflation Reduction Act in 2022, that price cost could fall below 70 cents, allowing
hydrogen to compete with diesel in the trucking industry as soon as 2026,the report said.ZThere
is significant global interest in hydrogen. In June 2021, the U.S. Department of Energy launched
its"Hydrogen Shot"which seeks to reduce the cost of clean hydrogen by 80%to$1 per 1 kilogram
in 1 decade ("1 1 1").3 With the current pricing of hydrogen, however, Intermountain is only
monitoring hydrogen at this time and will continue to consider it as a potential resource in future
IRPs.
2 https://www.spglobal.com/market-intelligence/en/news-insights/articles/2023/3/study-finds-green-
hydrogen-can-be-competitive-with-fossil-fuels-as-soon-as-2030-74961136
3 https://www.energy.gov/eere/fueIcelIs/hydrogen-shot
Page 67

3.5 Lost and Unaccounted for Natural Gas Monitoring
Intermountain Gas Company (IGC) is pro-active in finding and eliminating sources of Lost and
Unaccounted For (LAUF) natural gas. LAUF is the difference between volumes of natural gas
delivered to IGC's distribution system and volumes of natural gas billed to IGC's customers.
Intermountain Gas Company is consistently one of the best performing companies in the industry
with a LAUF percentage of 1.1% over the period of July 2024 to June of 2025.
IGC utilizes a system to monitor and maintain a historically low amount of LAUF natural gas.
This system is made up of the following combination of business practices:
• Perform ongoing billing and meter audits
• Routinely rotate and test meters for accuracy
• Conduct leak surveys on one-year and four-year cycles to find leaks on the system
• Natural gas line damage prevention and monitoring
• Implementing an advanced metering infrastructure system to improve the meter
reading audit process
• Monitorten weather location points to ensure the accuracy of temperature related
billing factors
• Utilize hourly temperatures for a 24-hour period, averaged into a daily temperature
average, ensuring accurate temperature averages for billing factors
3.5.1 Billing and Meter Audits
Intermountain Gas Company conducts billing audits to identify irregular usage with each billing cycle.
IGC also works to ensure billing accuracy of newly installed meters. These audits are performed
to ensure that the meter and billing system are functioning correctly to avoid billing errors. If
errors are identified, then corrective action is taken.
IGC also compares on a daily and monthly basis its telemetered usage versus the metered usage
that Northwest Pipeline records. These frequent comparisons enable Intermountain to find any
material measurement variances between Intermountain's distribution system meters and
Northwest Pipeline's meters.
Page 68

Billing and Meter Audit Results
2022 2023 2024
Dead Meters 164 235 171
Drive Rate Errors 2 48 4
Pressure Errors 14 25 37
`Totals 197 308 212
Table 9: 2022-2024 Billing and Meter Audit Results
3.5.2 Meter Rotation and Testing
Meter rotations are also an importanttool in keeping LAUF levels low. IGC regularly tests samples
of its meters for accuracy. Sampled meters are pulled from the field and brought to the meter
shop for testing. The results of tests are evaluated by meter family to determine the pass/fail of
a family based on sampling procedure allowable defects. If the sample audit determines that the
accuracy of certain batches of purchased meters are in question, additional targeted samples are
pulled and any necessary follow up remedial measures are taken.
In addition to these regular meter audits, IGC also identifies the potential for incorrectly sized
and/or type of meter in use by the larger industrial customers. IGC conducts a monthly
comparison to the billed volumes as determined by the customer's meter. If a discrepancy exists
between the two measured volumes, remedial action is taken.
3.5.3 Leak Survey
On a regular and programmed basis, IGC technicians check the company's entire distribution
system for natural gas leaks using sophisticated equipment that can detect even the smallest leak.
The surveys are done on a one-year cycle in business districts and a four-year cycle in other areas.
This is more frequent than the code requirement, which mandates leak surveys on one-year and
five-year cycles. When such leaks are identified, which is very infrequent, they are graded and
addressed according to grade. Grade 1 leaks are repaired immediately, Grade 2 leaks are
addressed within six months, and Grade 3 leaks are addressed within 15 months. This approach
is more aggressive than the industry standard, where lower grade leaks are often monitored for
safety and not repaired immediately.
3.5.4 Damage Prevention and Monitoring
Unfortunately,human error leadsto unintentional excavation damage to the distribution system.
When such a gas loss situation occurs, an estimate is made of the escaped gas and that gas then
becomes "found gas" and not "lost gas".
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When the Public Awareness and Damage Prevention department was created, it's focus was on
education to individuals, businesses, and agencies that partner with and interact with
Intermountain Gas Company. Industry education and awareness was centered around gathering
damage statistics and focused on meeting the regulatory requirements for educating the public,
excavation contractors and emergency responders.
Intermountain's recent efforts are aimed at educating the affected public and excavation
contractors on the importance of calling 811 prior to any type of digging. IGC has participated in
a variety of informational activities, including sponsored events,general awareness mailings, and
multi-media advertising, as well as site visits and training sessions on safe excavation practices
with excavation contractors.
The focus on education and awareness with the affected public has had an impact to reduce
excavation damage. However, the leading factor for damage to IGC facilities is still from
excavation contractors or individuals not submitting a locate request with the state one call
center before digging. IGC will continue to focus on public awareness and damage prevention
efforts on working with all excavation parties to increase awareness of the importance of
submitting a locate request and to use safe excavation practices while excavating, so individuals
and professional excavators can remain safe while excavating and reduce damage to IGC
underground facilities. Figure 29 shows the damage rate per 1,000 locates, and Figure 30 shows
the total locates for 2022 through 2024.
Damage Ratio per 1,000 Locate Tickets
9
7.93
8 6.98 7.51
7.28 7.09
7 6.43
6.36
6.1 6.1 5.93
6 5.73 5.53
5.04 5.28
4.87 4.89
5
4.25
4 3.5
3
2
1
0
Boise Nampa Twin Falls Pocatello Idaho Falls IGC Total
■2022 2023 ■2024
Figure 29:Damage Rates per 1,000 Locates by District
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Total Locate Requests
160,000 148,268
146,995
140,000
128,243
120,000
100,000
80,000
60,000 55,953 55,418
50,003 47,125
42,088
40,000
35,656
20,000
19,336 13,49J7,7289,752 9 99210,824 17,280 17,621
0 13 ■ ■ILIA MMM121,234
�■
Boise Nampa Twin Falls Pocatello Idaho Falls IGC Total
■2022 ■2023 .2024
Figure 30:Intermountain Locate Requests by District
Total Damages
900
815
800 776
725
700
600
500
400
300 305282 270
200 135
179 165 197
107 114 gg 126rr 125
100 �
0 U1 � m r o
Boise Nampa Twin Falls Pocatello Idaho Falls IGC Total
■2022 ■2023 ■2024
Figure 31:Intermountain Total Damages by District
Page 71

3.5.5 Weather and Temperature Monitoring
Intermountain Gas Company increased the number of weather monitoring stations in the early
2000's, from five to ten weather location points, to ensure the accuracy of temperature related
billingfactors.Additionally, IGC utilizes hourly temperatures for a 24-hour period, averting a daily
temperature average, ensuring accurate temperature averages for billing factors. The weather
and temperature monitoring provide for a better temperature component of the billing factor
used to calculate customer energy consumption.
3.5.6 Summary
Intermountain Gas Company continues to monitor LAUF levels and continuously improves
business processes to ensure the Company maintains a LAUF rate among the lowest in the natural
gas distribution industry.
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3.6 Core Market Energy Efficiency
The Company's Residential and Commercial Energy Efficiency Programs promote the wise and
efficient use of natural gas, which helps the Company's customers save money and energy.
Additionally, the Company's Energy Efficiency Programs will, overtime, help negate or delay the
need for expensive system upgrades while still allowing Intermountain to provide safe, reliable,
and affordable service to its customers.
3.6.1 Residential & Commercial Energy Efficiency Programs
The goal of Intermountain's Residential and Commercial Energy Efficiency Programs(EE Program)
is to acquire cost-effective demand side resources. Unlike supply side resources, which are
purchased directly from a supplier, demand side resources are acquired through the reduction
of natural gas consumption due to increases in the efficiency of energy use. Demand side
resources acquired through the Company's EE Program (also referred to as Demand Side
Management or DSM) ultimately allows Intermountain to displace the need to purchase
additional gas supplies, delay contracting for incremental pipeline capacity, and possibly negate
or delay the need for reinforcements on the Company's distribution system.The Company strives
to raise awareness about energy efficiency and inspire customers to reduce their individual
demand for gas through outreach and education.
An Energy Efficiency Charge for funding the Residential EE Program began on October 1, 2017.
Active promotion and staffing of the Residential EE Program launched in January 2018. Since the
launch, the Residential EE Program has continued to grow year over year in number of total
rebates claimed by customers. Intermountain launched its Commercial EE Program on April 1,
2021,and began collecting funds through a commercial Energy Efficiency Charge. Due to the slow
uptake of the Commercial EE Program,the EE was reduced to zero to decrease the over-collection
of funds while the commercial program gains awareness and participation.
3.6.2 Conservation Potential Assessment
In its 2023 IRP, the Company estimated DSM therm savings based on the Conservation Potential
Assessment (CPA) commissioned by Intermountain. The CPA provided a robust analysis of all
cost-effective DSM measures and is intended to support both short-term energy efficiency
planning and long-term resource planning activities. The objective of the CPA is to assess
achievable energy savings potential for the Intermountain service territory and apply the results
to:
• Inform Intermountain's energy efficiency goals, portfolio planning and budget setting,
• Contribute to Intermountain's Integrated Resource Planning process, and
• Identify new energy efficiency savings opportunities.
Page 73

Guidehouse was retained to perform the CPA. Guidehouse leveraged both IGC data and
secondary research and data sources to inform the modeling inputs for energy efficiency
potential. The scope of the study included conservation potential for both the residential and
commercial sectors over the 2024-2044 time period. During the time of the 2023 CPA,
Guidehouse also developed a model that would allow for updating inputs for future use.
Since the CPA was conducted for the 2023 IRP, there have been no changes to the energy
efficiency program. The Company weighed the fact that there have been no program changes
with the expense of commissioning a new full-scale study. To ensure responsible use of
resources, the Company opted for a targeted update rather than a comprehensive study, as the
existing model required only minor adjustments due to the absence of significant program
changes. This approach allowed the Company to achieve the necessary improvements at a
fraction of the cost of a full-scale study. Guidehouse was commissioned to update the global
input forecasts and measure inputs and extend the forecast period by two years. The
methodology used to conduct the 2023 conservation potential assessment is provided in the full
report in Exhibit 4. The model updates used to calculate the inputs for the 2025 IRP discussed in
the following section are provided in Exhibit 1.
Using data provided by the Company, Guidehouse updated the following global inputs in the
model:
• Building stock and sales
• Retail rates
• Avoided costs
• Inflation rate, and
• Discount rate
Compared to the 2023 CPA,
• Building stock and sales were forecasted slightly higher for the commercial sector and
modestly lower for the residential sector.
• Retail rates were forecasted to be higher for 2026 and beyond.
• Avoided costs are forecasted to be lower than the 2023 CPA.
• Inflation rate is forecasted to be higher at 3.99%compared to 3.15% in the 2023 CPA, and
• Discount rate is forecasted to be lower at 2.68%, compared to 3.51% in the previous CPA.
The measure inputs, savings, costs, and estimated useful lifetimes, were updated using the IGC
Technical Reference Manual. The following commercial measures were updated: commercial
kitchen fryer, steamer, convection oven, combination oven, dishwasher, high efficiency
condensing boiler, smart thermostat, storage water heater, tankless water heater, furnace gas
heat pump, condensing unit heater, boiler reset control and pipe insulation. The following
residential measures were updated: Whole Home Tier I and II, 95% AFUE furnace, 97% AFUE
Page 74

Furnace, smart thermostat, storage water heater, tankless water heater, 95% AFUE boiler and
95%AFUE combination boiler.
3.6.3 Energy Efficiency Potential
To develop an estimate of the potential for gas energy efficiency in Intermountain's service
territory over a 20-year horizon, three categories of potential savings were calculated by
Guidehouse: technical, economic, and achievable energy savings.Technical potential assumes all
eligible customers adopt the highest level of efficiency available, regardless of cost effectiveness.
Next, measures are screened for cost-effectiveness to estimate economic potential. Economic
potential is a subset of technical potential but includes only the measures that have passed the
benefit-cost test chosen for measure screening. Intermountain uses the Utility Cost Test (UCT)
for cost-effectiveness testing. The third category of savings potential, achievable potential, is a
calculation of energy efficiency savings that could be expected in response to specific levels of
program incentives and assumptions about existing policies, market influences, and barriers.This
screening of savings potential is illustrated in Figure 32.
Technical Potential
Total energy savings available by
use and sector, relevant to current
population forecast
EconomicPotential
L Utility Cost Test(UCT)cost-
effectiveness
screen
Achieva
ble
Potential
. .-
adopted .
ro .
Figure 32: Guidehouse: Types of Savings Potential
The three types of savings potential for the study time period is shown in Figure 33.
Page 75

350
300
E
a`, 250
200
0 150
2
0
a_
100
c
cn 50
0
2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2046
— Technical —Economic Achievable
Figure 33: Guidehouse Analysis 2025: Savings Potential
Figure 34 illustrates the gas energy achievable potential by sector as a percentage of forecasted
sales.
Gas Energy Achievable Potential by Sector as a Percent of Total Sales
5%
u 4%
m
`o
a
a 3%
A
A
C
u
a 2%
1%
0%
2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046
-Commewial -Residential
Figure 34: Guidehouse Analysis 2025:Achievable Potential as a Percent of Total Sales
Page 76

As was explored in the 2023 CPA, Guidehouse ran the same four scenarios to examine how
changes in customer attitudes and awareness regarding energy efficiency, and approaches to
incentive amounts, could impact potential savings. The four scenarios examined included
Business as Usual (BAU), Unconstrained Historical budget, Medium Incentive,and combined High
Incentive, High Adoption. Scenario details are outlined in Figure 35, while savings potential for
all scenarios is shown in chart format in Figure 36.
Unconstrained Historical Budget:This
Business as Usual(BAU):This scenario does scenario reflects a ramp up of customer adoption
not represent an intentionally defined change to ' of natural gas energy efficiency over a l0-year
the model;it does reflect an assumption that future period from the start s the EE program(through
program budgets will be closely correlated with ' with),driven by increased IGC program activity
IGC's historic EE program spending. without constraining program spending h historic
levels.Incentive levels are consistent with Business-
0 es-Usual Scenario.
Medium Adoption:This scenario increases the 10 High Incentive,High Adoption:this scenario
adoption parameters compared to the reflects the savings possible by increasing the
unconstrained historical budget scenario and incentives from 50%of measure incremental cost
increases model parameter values relating to to 65%of incremental cost and further increasing
customer awareness and willingness to adopt ® the customer awareness and willingness to adopt
energy efficient technologies.Incentive levels are energy efficiency measures to the highest values
consistent with Business as Usual Scenario. based on Guidehouse's experience and rules of
thumb.
Figure 35: Guidehouse Savings Potential Scenarios
Achievable Potential,All Scenarios
160
140 —
120
Op
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w /
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a 60 /
Q /
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2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046
&ainess as usuai — —Unconstrained Historic Budget Medium Adoption Mgh Adoption,high incentive
Figure 36: Guidehouse Analysis 2025:Four Scenarios of Achievable Potential
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Guidehouse also compared Intermountain's historic accomplishments to the achievable
potential estimated in the 2023 CPA and the current 2025 CPA, illustrated in Figure 37.A measure
competition group is a group of measures that serve the same purpose.The measure competition
group with the highest potential is Residential Furnaces, serving space heating. The Residential
Furnace competition group consists of 95 AFUE Furnace, 97 AFUE Furnace and Gas Heat Pump.
The key change with the 2025 CPA is that savings and costs for the 95 AUFE and 97 AFUE furnaces
were reduced by approximately 75% when the model was updated with saving and cost
estimates from the IGC Technical Reference Manual. The gas heat pump measure, which has
much higher savings, is cost-effective in more cases than in the previous CPA, but the increase in
savings for gas heat pumps is not enough to offset the reduction from the furnace measures.
Historic Accomplishments Compared to past and Curent Study
Achievable Potential Results
2.0
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ip N N N N N N N N N N N N N N N N N N N N N N N N N N N N
3
C
a 2023 Study(Business as Usual) t2025 Study(Business as Usual) Historic Accomplishments
Figure 37: Guidehouse Analysis 2025
The combined effect of the global input updates increased benefit-cost ratios (UCT) compared to
the 2023 CPA. This was driven by higher avoided costs in later years, combined with a lower
discount rate, making the future years more important.
Figure 38 illustrates that for the Business-as-Usual scenario achievable potential results are
overall lower than the 2023 CPA, and the difference grows overtime.
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Incremental Achievable Potential(therms/yr)
BAU(Seen 1) 20241 20251 20261 20271 20281 20291 20301 20351 2040
2023 CPA Total 1,681.489 1,609,817 1.636.834 1,639,515 1,629,649 1.569.179 1.555,721 1,658,211 1,616.968
2025 CPA Total 1.435,954 1,563.629 1.325.611 1.219,682 1,232.025 1.217.600 1.164.390 973.022 836.745
Change -15% -3% -19% -26% -24% -22% -25% J1
2023 CPA lResidential 1.656.777 1.582,9701 1,607.031 1,606.593 1,593.4411 1.529.423 1,511.952 1,587.032 1,497,466
2025CPA lResidentiat 1,420,1731 1,537,6521 1.297.3841 1,188,5691 1,198,0971 1.180.7631 1.124,447 910.776 733.919
Change -14% -3% -19% -26% -25% -23% 26%
2023 CPA Commercial 124,712 26,848 29.8041 32,921 36,208 39.7561 43,769 71,179 119.502
2025CPA lCommercial 1 15.7811 25.9771 28.2271 31.1131 33.9281 36.8371 39.943 62.246 102.826
Change 1 -38% -3% -5% 5% -6% -7% .9% -13% -14%
Figure 38: Guidehouse Analysis 2025
The Business-as-Usual scenario based on achievable potential is the most conservative estimate
for IRP planning and was also applied in the 2023 IRP. By using this scenario, the Company
bases IRP resource decisions on achievable, cost-effective savings that reflect actual program
data and market conditions. This approach offers a stable foundation for long-term planning
and accommodates future adjustments in response to program enhancements or market
developments.
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3.7 Large Volume Energy Efficiency
Through discussions with customers, maximizing plant efficiency by optimizing production
volumes while using the least amount of energy is a very high priority for the owners, operators,
and managers of Intermountain's large volume facilities. Nearly twenty years ago Intermountain
developed an informational tool using Supervisory Control and Data Acquisition (SCADA) and
remote radio telemetry technology to gather, transmit and record the customer's hourly therm
usage data. This data is saved in an internal database and made available to customers and their
marketers/agents via an internal server on a password protected website.
For gas emergencies please call 1-877-777-7442
INTERMOUNTAIN°
GAS COMPANY
A Subsidiary of MDU Resources Group,Inc.
Forgot Password?
Figure 39:Large Volume Website Login
In addition to SCADA, a new technology, Encoder Receiver Transmitters (ERTs) are being added
to some meters that did not have SCADA. The equipment is able to transmit usage information
via fixed network, similar to SCADA, and provide timely usage information on usage.
Regardless of which technology is being implemented, usage data is useful in tracking and
evaluating energy saving measures, new production procedures and/or usage characteristics of
new customer equipment. To deploy these tools, Intermountain installs equipment on
customers' meters to record the meter volume each hour. That data is then transmitted via
radio/telemetry communication technology to Intermountain's servers so it can be made
available to customers.
In order to provide Intermountain customers access to this data, the Company has designed and
hosts a Large Volume website, which is pictured in Figure 39. The website is available on a 24/7
basis for Large Volume customers to log-in via the Internet using company specific username and
customer managed passwords. After a successful log-in, the user immediately sees a chart
showing the last 30 days of hourly usage for the applicable meter or meters. The customer also
has the option to adjust the date range to see just a few hours or up to several years of usage
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data. An example of a month's worth of data is provided in Figure 40.The user can also download
the data in CSV format to review, evaluate, save, and analyze natural gas consumption at their
specific facility on an hourly, weekly, monthly, and annual basis as far back as 2017. Each
customer may elect to allow one or multiple employees to access the site. Logins can also be
created to make this same data available to a transport customer's natural gas marketer.
Natural Gas Usage
The gas day begins at 8 00 AM and ends at 7 59 AM the next day
10
8
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c 6
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2
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c ti
ono
ti ti ti ti ti ti ti ti ti +,
Figure 40: Natural Gas Usage History
The website also contains a great deal of additional information useful to the Large Volume
customer. Customers can access information such as the different tariff services offered,answers
to frequently asked questions and a potential marketer list for those interested in exploring
transport service.The customer is also provided a "Contact Us" link and, in order to keep this site
in the most usable format for the customer, a website feedback link is provided. The site allows
the Company to post information regarding things such as system maintenance, price changes,
rate case information and any other communication that might assist the customer or its
marketer.
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3.8 Avoided Costs
3.8.1 Overview
The avoided cost represents those costs that the Company does not incur as a result of energy
savings generated by its Energy Efficiency Program. The calculation is used both to
economically evaluate the present value of the therms saved over the life span of a measure
and to track the performance of the program as a whole.
Avoided costs are forecasted out 30 years in order to properly assess Energy Efficiency
measures with longer lifespans. This forecast is based on the performance of the Company's
portfolio under expected market conditions. The Avoided Cost values can be found in Exhibit
5.
3.8.2 Costs Incorporated
Intermountain's avoided cost calculation contains the following components:
ACnominol= CC+ TC+ VD
Where:
• ACnominal=The nominal avoided cost for a given year.
• CC=Commodity Costs
• TC=Transportation Costs
• VDC=Variable Distribution Costs
The following parameters are also used inthe calculation of the avoided cost:
• The assumed forward-looking annual inflation rate is 2.68%. (Inflation was updated
to 3.99%this year to account for the high inflation rates).
• The discount rate is derived using Intermountain's tax-effected cost of capital.
• Standard present value and levelized cost methodologies are utilized to develop a
real and nominal levelized avoided cost by year.
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3.8.3 Understanding Each Component
Commodity Costs
Commodity costs represent the purchase price of the natural gas molecules that the Company
does not need to buy due to therm savings generated by its Energy Efficiency Program. To
calculate the commodity costs, the Company first utilizes price forecasts included in its IRP for
three primary basins (AECO, Sumas, and Rockies) then weights these forecasts based on
Intermountain's historical day-gas purchase data. Day-gas purchases representthe first costs that
could be avoided through Energy Efficiency Program savings. To account for the seasonal nature
of energy savings,the weighted price is shaped by normal monthly weather, measured in heating
degree days with a base of 65 degrees. The original basin price forecasts span through 2040 and
then an escalator is applied through the remainder of the forecast period.The gas price forecasts
will be updated in each IRP planning cycle.
Transportation Costs
Transportation costs are the costs the Company incurs to deliver gas to its distribution system.
As the Company's Energy Efficiency Program generates therm savings, the Company can reduce
pipeline capacity needs and monetize any excess capacity to reduce costs for all customers
through credits in the Company's annual Purchased Gas Cost Adjustment (PGA) filing. The
Company calculates the per therm transportation cost as the weighted average of the gas
transportation costs listed on the Company's residential and commercial tariffs. The nominal
value of the transportation cost is increased each year by the model inflation rate of 3.99%. The
inflated nominal value is then discounted back to today's dollars as part of the final step in the
avoided cost calculation. The Company will update the transportation cost each year to reflect
the most current gas transportation cost as filed in its PGA.
Variable Distribution Costs
Variable distribution costs are the avoidable portion of costs incurred by Intermountain to
deliver gas to customers via its distribution system. Lowering gas consumption through the
Company's Energy Efficiency Program allows Intermountain to delay costly capacity
expansion projects and utilize existing pipeline infrastructure more efficiently. While these
cost benefits are intuitively apparent, the Company and its Stakeholder group are
investigating methods to quantify these savings. The Company is currently using a
placeholder value of zero for this component.
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4. Optimization
4.1 Distribution System Planning
4.1.1 Overview
Intermountain strives to provide safe and reliable service to its customers. As part of
Intermountain's distribution planning process Intermountain reviews it's systems for predicted
growth and will identify and address capacity deficits related to growth. If a capacity deficit is
identified, reinforcement alternatives are compared, and the optimized reinforcement is
selected and budgeted within Intermountain's five year budget with consideration to cost,
system benefits and longterm planning.
This section will cover how Intermountain models its distribution systems, identifies deficits,
proposes reinforcement options to address deficits, reviews and selects reinforcement options,
and how projects are put into the capital budget.
4.1.2 System Dynamics
Intermountain operates a diverse system through Idaho over a range of pipeline diameters and
operating pressures. Intermountain's natural gas distribution system consists of approximately
7,471 miles of distribution and 284 miles of transmission in Idaho. Intermountain system is also
composed of facilities including regulator stations, valve stations, odorizers, heaters and
compressor stations.
In general, Intermountain's distribution systems originate at a gate station connected to an
interstate pipeline. At the gate station, Intermountain takes custody of the natural gas and
provides odorization and pressure control to serve downstream distribution and transmission
pipelines.
4.1.3 Network Design Fundamentals
A natural gas pipeline is constrained by the laws of fluid mechanics which dictate that a pressure
differential must exist to move gas from a source to any other location on a system. Equal
pressures throughout a closed pipeline system indicate that neither gas flow nor demand exist
within that system. When gas is removed from some point on a pipeline system,typically during
the operation of natural gas equipment, then the pressure in the system at that point becomes
lower than the supply pressure in the system. This pressure differential causes gas to flow from
the supply pressure to the point of gas removal in an attempt to equalize the pressure throughout
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the distribution system. The same principle keeps gas moving from interstate pipelines to
Intermountain's distribution systems. It is important that engineers design a distribution system
in which the beginning pressure sources, which could be from interstate pipelines, compressor
stations or regulator stations, have adequately high pressure, and the transportation pipe
specifications are designed appropriately to create a feasible and practical pressure differential
when gas consumption occurs on the system. The goal is to maintain a system design where load
demands do not exceed the system capacity; which is constrained by minimum pressure
allowances at a determined point, or points, along the distribution system,and/or maximum flow
velocities at which the gas is allowed to travel through the pipeline and related equipment,
and/or maximum volumetric flow through facilities.
Due to the nature of fluid mechanics there is a finite amount of natural gas that can flow through
a pipe of a certain diameter and length within specified operating pressures; the laws of fluid
mechanics are used to approximate this gas flow rate under these specific and ever changing
conditions. This process is known as "pipeline system modeling." Ultimately, gas flow dynamics
on any given pipeline lateral and distribution system can be ascertained for any set of known gas
demand data. The maximum system capacity is determined through the same methodology
while calculating customer usage during a peak heating degree day.
To evaluate intricate pipeline structures, a system model is created to assist Intermountain's
engineering team in determining the flow capacity and dynamics of those pipeline structures.
For example, before a large usage customer is incorporated into an existing distribution system
the engineer must evaluate the existing system and then determine whether or not there is
adequate capacity to maintain that potential new customer along with the existing customers,
or if a capacity enhancement is required to serve the new customer, and which capacity
enhancement option is optimal. Modeling is also important when planning new distribution
systems. The correct diameter of pipe must be designed to meet the requirements of current
customers and reasonably anticipate future customer growth.
4.2 Modeling Methodology
Intermountain utilizes a hydraulic gas network modeling and analysis software program called
Synergi Gas, distributed and supported by DNV (software provider), to model all distribution
systems and pipeline flow scenarios. The software program was chosen because it is reliable,
versatile, continually improving and able to simultaneously analyze very large and diverse
pipeline networks. Within the software program, individual models have been created for each
of Intermountain' s various distribution systems including transmission and high pressure
laterals, regulator stations, compressor stations, distribution system networks and large
diameter service connections.
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Each system's model is constructed as a group of nodes and facilities. Intermountain defines a
node as a point where gas either enters or leaves the system, a beginning and/or ending location
of pipe and/or non-pipe components, a change in pipe diameter or an interconnection with
another pipe. A facility is defined in the system as a pipe, valve, regulator station, or compressor
station; each with a user-defined set of specifications. Intermountain's distribution systems are
broken into 6 models for ease of use and to reduce the time requirements during a model run
analysis.
Synergi can analyze a pipeline system at a single point in time or the model can be specifically
designed to simulate the flow of gas over a specified period of time;which more closely simulates
real life operation utilizing gas stored in pipelines as line pack. While modeling over time an
engineer can write operations that will input and/or manipulate the gas loads, time of gas usage,
valve operation and compressor simulations within a model, and by incorporating the forecasted
customer growth and usage provided within this integrated resource plan Intermountain can
determine the most likely points where future constraints may occur. Once these high priority
areas are identified, research and model testing are conducted to determine the most practical
and cost-effective methods of enhancing the constrained location.
4.2.1 Model Building Process
Intermountain's models are rebuilt every three years and are regularly maintained between
rebuilds. To rebuild the models, Intermountain exports current GIS data to create the spatial
models and exports historical billing data from CC&B to bring into the Customer Management
Module (CMM)to create an updated demands file. Intermountain's models were rebuilt in 2025.
4.2.2 Usage Per Customer
The IRP planning process utilizes customer usage as an essential calculation to translate current
and future customer counts into estimated demands on the distribution system and total
demand for gas supply and interstate transportation planning. The calculated usage per
customer is dependent upon weather and geographic location.
Intermountain utilizes a Customer Management Module (CMM) software product, provided by
DNV as part of their Synergi Gas product line, to analyze natural gas usage data and to predict
usage patterns on the individual customer level.
The first step in operating CMM is extensive data gathering from the Company's Customer
Information System (CIS), CC&B. CC&B houses historical monthly meter read data for each of
Intermountain's customers, along with daily historical weather and the physical location of each
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customer. The temperature data is associated with each customer based on location and then
related to each customer's monthly meter read according to the date range of usage.
After the correct temperature information has been correlated to each meter read, a base load
and temperature dependent load are calculated for each customer through regression analysis
over the historical usage period. DNV GL states that it uses a "standard least-squares-fit on
ordered pairs of usage and degree day" regression. The result is a customer specific base load
that is weather independent, and a heat load that is multiplied by a weather variable, to create
a custom regression equation.
Should insufficient data exist to adequately predict a customer's usage factors, then CMM will
perform factor substitution. Typically, the average usage of customers in the same geographical
location and in the same customer rate class can be used to substitute load factor data for a
customer which lacks sufficient information for independent analysis.
With all the structural shifts in historical data, and the significantly increased quantity of data
utilized for regression, Intermountain has selected a five-year time series to develop the usage
per customer equations for model rebuilds. The selected time series is aligned with the
recommended time study from DNV.
The Company recognizes that there could be significant differences in the way its customers use
natural gas throughout its geographically and economically diverse service territory. Being
sensitive to areas that may require capital improvements to keep pace with demand growth,
Intermountain separates customers by districts and then determined specific usages per
customer for each.
4.2.3 Fixed Network
Over the past couple of years Intermountain has been expanding it's fixed network system.
Intermountain' s fixed network will allow for real time data of customer demand/usage at the
meter. The fixed network will be another resource to check peak day loading and usage per
customer.
Intermountain started installing fixed network in 2021, currently Intermountain' s fixed network
system covers 82% of ERT meters and the devices are still being added to the fixed network
system.
In 2021 CMM data was compared to a small set(100 data points) of available fixed network loads
resulting in a 12% difference between the two systems. In 2023 the comparison was made again
with a much larger set (892 data points) of available fixed network loads on a cold weather day
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in early 2023. The most recent comparison shows a 2% difference between the fixed network
data and the calculated CMM loads.The percent difference improvement between the 2021 and
2023 comparisons can be largely attributed to the availability of a larger fixed network data set
from across the entire state versus a smaller set of data available for only one area. Overall, the
fixed network data comparison agreed with CMM usage per customer loading based on the
heating degree day providing confidence in CMM's usage per customer predictions.
4.2.4 Model Validation
To check the usage per customer, Intermountain validates the models for a specific temperature
event. To validate the model, Intermountain will gather all pressures and flow data available on
its system for a specific date and time and will then set the model to the temperature
experienced to see how the model is performing. During model validation pressures and flows in
the model are compared to actual pressure and flow data.Comparing the model results to actuals
pressures and flows allow the Company to validate the model and have confidence that the usage
per customer from CMM is accurate when compared to temperature and flow data in each
geographic area.
Once a model is validated it is then ramped up to its peak degree day, based on 30 years of
historical temperature data, to create a design day model. Intermountain's peak heating degree
days by district are shown in Figure 41.
District HDD Avg Daily Temperature (OF)
Boise 75 -10
Nampa 68 -3
New Plymouth & Payette 78 -13
Pocatello 82 -17
Idaho Falls 88 -23
Twin Falls 77 -12
Ketchum 82 -17
Figure 41:Peak Heating Degree Day
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As can see from Figure 41, Intermountain operates in diverse regions that range from mountain
to desert, which is why the models are broken down by district. Intermountain heating degree
day calculations are based on customers turning on their heat when temperatures drop below
65 degrees Fahrenheit. The heating degree day is calculated by subtracting the average daily
temperature from 65 degrees Fahrenheit.
4.2.5 Distribution System Planning Process
Intermountain spends significant time and resources on building and maintaining its design day
models. Intermountain uses its design day models to review large customer requests, model
renewable natural gas injection onto Intermountain's systems, design and size pipe and non-pipe
facilities, long term planning, model growth predictions, identify system deficits, determine
system reliability, generate emergency plans during large system outages and line breaks,
optimize enhancement options and support cold weather action plans.
A system deficit is defined as a critical system that has reached or exceeded the capacity to serve
customer demands. Critical system examples that are limiting capacity include pipeline diameter
restrictions (bottlenecks), below minimum inlet pressure to a regulator station or high pressure
system to meet a downstream operating pressure, not meeting a required customer delivery
pressure, or a physical component that is limiting capacity like a regulator which has a rated flow
capacity for the specific conditions that the regulator is operating under as published by the
manufacturer.
As part of the IRP process, Intermountain completes a comprehensive review of the Company's
distribution system models to ensure that the Company can maintain reliable service to
customers during design day events. Intermountain also completes annual reviews of its
distribution system models as part of the annual budgeting process and continually updates the
five-year budget, as needed, based upon new information that impacts the five-year plan. If a
deficit is predicted, the system is evaluated, and reinforcement options are reviewed, with an
optimized reinforcement selected. The selected reinforcement will then be placed into the
capital budget based on the timing needs of the predicted deficit.
The Engineering services department works closely with Field Operations coordinators, Energy
Services representatives, Gas Supply, and district management to assure the system is safe and
reliable. As towns develop, the need for pipeline expansions and reinforcements increase. The
expansions are historically driven by new city developments or new housing plats. Before
expansions and installation can be constructed to serve these new customers, engineering
analysis is performed. As new groups of customers seek natural gas service, the models help
engineers determine how best to serve them reliably.
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4.2.6 Distribution System Enhancements
Once a deficit has been identified, Engineering will propose enhancement solutions to address
the deficit. Each of Intermountain's systems are unique in pipeline dynamics and will be
optimized using different enhancement solutions.
Distribution enhancements typically include:
• Pipeline reinforcement such as replacements
• Pipeline loops and/or back feeds
• Operating pressure increase
• Uprates
• Facility upgrades,
• Additional regulator station feeds or gate station supply
• Compressor stations
• Demand side management strategies
Pipeline looping is the most common method of increasing capacity in an existing distribution
system. It involves installing new pipe parallel to an existing pipeline that has, or may become, a
constraint point. Constraint points inhibit flow capacities downstream of the constraint creating
inadequate pressures downstream during periods of high demand. When the parallel line
connects to the system, this alternative path allows natural gas flow to bypass the original
constraint and bolsters downstream pressures. Looping can also involve connecting previously
unconnected mains. The feasibility of looping a pipeline depends upon the location where the
pipeline will be constructed. Installing gas pipelines through private easements, residential
areas, existing asphalt, environmentally sensitive areas, and steep or rocky terrain can increase
the cost to a point where alternative solutions are more cost effective.
Pipeline replacement involves replacing existing pipe with a larger diameter pipe. The increased
pipe diameter relative to surface area results in less friction, larger flow capacity, and therefore,
a lower pressure drop. This option is usually pursued when a pipe is damaged or has integrity
issues. If the existing pipe is otherwise in satisfactory condition, the pipeline looping option is
typically optimal, as it continues to utilize existing pipe.
Pipeline uprating increases the maximum allowable operating pressure of an existing pipeline.
This enhancement can be a quick and relatively inexpensive method of increasing capacity in the
existing distribution system instead of constructing more costly additional facilities. However,
safety considerations and pipe regulations may prohibit the feasibility or lengthen the time
before completion of this option. Also, increasing line pressure may produce leaks and other
pipeline damage, creating costly repairs, or prohibiting the proposed uprate altogether. A
thorough facility review is conducted to ensure pipeline integrity before an uprate is conducted.
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Pressure regulators or regulator stations reduce pipeline pressure at various stages in the
distribution system. Regulation provides a specified and constant outlet pressure before natural
gas continues its downstream travel to a city's distribution system, a customer's property, or a
natural gas appliance. Regulators also ensure that flow requirements are met at a desired
pressure regardless of pressure fluctuations upstream of the regulator. Regulators are at gate
stations, district regulator stations, high pressure service sets, farm taps, and customer meters.
Utilization and strategic positioning of new stations can be very helpful in increasing system
reliability and capacity
Compressor stations present a capacity enhancing option for pipelines with significant natural
gas flow and the ability to operate at higher pressures. For pipelines experiencing a relatively
high and constant flow of natural gas, a large volume compressor installation along the pipeline
will boosts downstream pressure, which will increase the downstream capacity of the pipeline.
A second option is the installation of smaller compressors located close together or strategically
placed along a pipeline. Multiple compressors accommodate a large flow range and use smaller
and very reliable compressors. These smaller compressor stations are well suited for areas where
gas demand is growing at a relatively slow and steady pace, so that purchasing and installing
these less expensive compressors over time allow a pipeline to serve growing customer demand
into the future.
Compressors can be a cost-effective option to resolving system constraints; however, land
constraints, regulatory and environmental approvals to install a station, along with engineering
and construction time, can be significant deterrents. Adding compressor stations typically
involves considerable capital expenditure and long-term operations and maintenance costs for
the life of the facility.
4.2.7 Distribution System Enhancement Considerations
Each distribution system enhancement option is analyzed during the selection process with
consideration to scope, cost, timing, system benefits, long term planning and feasibility. For any
project over 1 million dollars there is a more robust analysis for the project and supporting
documentation, and engineers work collaboratively with management and directors to examine
pipeline alternatives to ensure all alternatives were considered.
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4.2.8 Distribution System Enhancement Selection Guidelines
Engineers work collaboratively with the manager and directors to select the most favorable
enhancement solution to address the deficit. Engineering uses the following criteria to select
distribution system enhancements:
• Non pipe alternatives including:
• Pressure Increases/Uprates if feasible
• Compressor Stations if permitting (emission/zoning, etc.) is favorable and land is
available and cost effective for project.
Pipe Options:
• The shortest segment(s) of pipe that addresses the deficit.
• The segment of pipe with the most favorable construction conditions that supports longterm
operations and maintenance activities.
• Route selection that minimizes environmental concerns, i.e. avoid water crossings, wetlands
and environmentally sensitive areas.
• Route selection that minimizes impacts to the community, i.e. road closures or city road
moratoriums.
• Route selection that provides opportunity to add additional customers.
• Total construction costs including restoration.
4.2.9 Capital Budget Process
Intermountain annually goes through the capital budget process to approve a five-year capital
budget. Intermountain's annual budget process begins in June and will typically go through three
to five revisions before it is accepted and approved in late November by the board of directors.
Engineers support the capital budgeting process by submitting distribution system enhancement
projects to the budget. Engineers will work collaboratively with managers and directors to
prioritize projects in the budget based on predicted timing needs with the goal of minimizing risk
to ensure that the Company can continue to provide safe and reliable service to Cascade's
customers. Figure 42 provides a schematic representation of the distribution system selection
process to the capital budget.
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District Info:
Design Day
IRP Growth Data -City Developments
Models
-New Housing Plats
IF
System Limitations
Computer Model Pressure
Concerns
BENEFIT
FEASIBILITY Identify Potential Projects and
10 Enhancement Types
(Individually)
COST
1
BENEFIT
Evaluate and Select Projects
00 Based On Priority and
FEASIBILITY Analysis Results
COST
Schedule Projects Into Budget
Figure 42:Distribution System Planning Process Flow
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intermountain's budget goes through several revisions and reviews at all levels in the
organization to make sure that projects are properly justified and necessary. Every year as part
of the capital budget process Intermountain projects are re-reviewed and revisions will be made
to the projects, as needed, as new information becomes available as part of an iterative IRP
process.
4.2.10 Conclusion
Intermountain's goal is to maintain a reliable natural gas distribution system in order to cost-
effectively deliver natural gas to every core customer. This goal relies on Intermountain being
proactive in addressing current and future system deficits. Intermountain's five year capital
budgeting process allows time for projects to go through alternative analysis considerations and
allows extended design and construction timelines required for large projects. The iterative
process of Intermountain's IRP and capital budgeting process will allow Intermountain the ability
to adapt to the changing dynamics of the natural gas industry.These dynamics include renewable
natural gas coming onto Intermountain's systems, building code changes, energy efficiency
programs and hydrogen blending.
Page 94

4.3 Capacity Enhancements
4.3.1 Overview
Throughout previous sections of the IRP, it has been shown that projected growth throughout
Intermountain gas' distribution systems could possibly create capacity deficits in the future.
Using a gas modeling system that incorporates total customer loads, existing pipe and system
configurations along with current distribution system capacities, each potential deficit has been
defined with respect to timing and magnitude. If any such deficit occurs then the system capacity
enhancements is evaluated, capacity enhancement alternatives are compared in the
optimization model, and a final capacity enhancement is selected with consideration to cost,
capacity increase and long-term planning. After the capacity enhancement has been selected it
is budgeted into Intermountain gas's 5-year budget based on when the capacity enhancement
needs to occur to avoid capacity deficiencies.
The five identified Areas of Interest (A01) that were analyzed under specific design conditions
are: Canyon County, State Street Lateral, Central Ada County, Sun Valley Lateral and the Idaho
Falls Lateral. Each of these areas are unique in their customers served and their pipeline
characteristics, and the optimization of each requires different enhancement solutions.
As part of the IRP capacity review for each A01 the following items are summarized below by AOI:
■ A01 Summary/System Dynamics
■ Capacity Limiter
■ Capacity Enhancement Alternatives Considered
o Details/Scope
o Benefits
o Additional Considerations
o Cost
■ Direct Cost
■ Net Present Value Cost'
o Capacity
■ Table Summary of Capacity Enhancement Alternatives Considered
■ Capacity Enhancement Selected
o Reasoning
o Timing
■ 2023 IRP Updates (as applicable)
Included at the end of the A01 Summaries is a summary with Intermountain Gas's five-year
planning and timing of all the capacity enhancement selected and corresponding capacity
increases for the AOIs.
' See Exhibit 6— NPV Analysis for information on the Company's net present value cost
evaluation. To determine net present cost IGC pulled various 0&M cost for the alternatives
proposed based on actual O&M costs over the last three years and then calculated the three-
year average cost. O&M cost details are shown in the tab with the O&M cost label.
Page 95

4.3.2 Canyon County
AO1 Summary/System Dynamics
The Canyon County area of interest consists of an interconnected system of high-pressure (HP)
pipelines that serve communities from Star Road west to Highway 95. The system originally
serving Nampa and Caldwell was continually extended west to additional towns and industrial
customers. In 2013 the Canyon County system was connected to, and back fed from, a new
pipeline installed to the town of Parma. This Parma Lateral 6-inch HP pipeline project provides a
secondary feed to the Canyon County area. The next large system enhancements occurred in
2018, 2021 and 2024 with the 12-inch Ustick Phases 1-3 pipeline projects installed on the east
side of Caldwell, which was required to remove pipeline flow restrictions through a bottleneck
area.
Capacity Limiter
Due to the significant amount of capital investment in Canyon County over the last couple of
years no reinforcements are needed to meet 2030 growth predictions.
4.3.3 Central Ada County
AOI Summary/System Dynamics
Central Ada County AO1 consists of high pressure and distribution pressure systems in an area of
Ada County that has historically experienced high levels of growth and development. The system
currently has high pressure supplied from Chinden Boulevard on the north side of the defined
area and high pressure supplied from Victory Road on the south side of the defined area. Initially
the continued growth demands between these two separate systems taxed the Chinden high
pressure pipeline and the branch lines supplied from Chinden. In 2016 an 8-inch high pressure
pipeline was installed on Cloverdale Road connected the Victory system to a branch of the
Chinden system, which alleviated the excess demand supplied from the Chinden pipeline. The
connection between the two systems was an initial step in the long-term plan, and while the
project successfully increased capacity in the area, the two systems are operating at different
pressures and are currently disconnected through system valving. In 2023 the South Boise Loop
project was completed which further reinforced the Boise high pressure system from the Kuna
Gate Upgrade to Cloverdale and Victory to supply an additional pressure source to the Victory
high pressure system served by the Meridian Gate to increase capacity to Boise and connect the
Chinden high pressure system to the South Boise Loop.
Page 96

Capacity Limiter
Due to the significant amount of capital investment in the Ada County AOI with the 12-inch South
Boise Loop (12-inch Cloverdale high pressure) and Kuna Gate upgrade completed in 2023 no
reinforcements are needed to meet 2030 growth predictions.
4.3.4 State Street Lateral
AOI Summary/System Dynamics
The State Street Lateral is a sixteen mile stretch of high pressure, large diameter main that begins
in Middleton and runs east along State Street serving the towns of Star, north Meridian, Eagle
and into northern Boise. The lateral is fed directly from a gate station along with a back feed
from another high-pressure pipeline from the south. Much of the pipeline is closely surrounded
by residential and commercial structures that create a difficult situation for construction and/or
large land acquisition, thus making a compressor station or Liquified Natural Gas (LNG)
equipment less favorable.
Capacity Limiter
Due to explosive growth in Boise and north towards Eagle this AOI requires a capacity
enhancement by 2026 to meet IRP growth. The current capacity limiter to this AOI is a 12-inch
HP bottleneck on State Street and a 4-inch HP bottleneck on Linder Rd as shown in yellow in
Figure 43.
.. �-'4�.. .. ��• ^��:t4.�0 � _•;r'--' -' is
�• � : •.: J.`s;r�J •• � .`C��ti.ituV l-�... .r `:.Y, 1 �{}1 rr. }tZ -
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Figure 43: State Street Lateral Capacity Limiter
Page 97

Capacity Enhancement Alternatives
Two alternatives were considered in the 2021 IRP. Those alternatives included the State Street
Phase II uprate and replacing the 12-inch on State Street and 4-inch HP on Linder Road.The State
Street Phase II uprate was chosen in 2021 as the lowest cost alternative.
Capacity Enhancement Selected
The State Street Phase II uprate consists of pressure testing and then uprating 12,000 feet of 12-
inch HP on State Street and 10,500 feet of 4-inch HP on Linder Road to certify a 500 psig MAOP.
In addition to the uprate work a new regulator station would be installed and several existing
regulator stations would be retired along with a PE trunk line to support the uprate activities.The
State Street Phase II uprate is shown in Figure 44.
,.- ►1 •[/".! i�-- . ....•...
•-. - 'j .+ir .! . ,.'•�.•a`Y tt-V.r•' T•t .'�; .;:t j J'J:: v..sl' .'.:�':. �,- �•'+�,y�•;
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Figure 44: State Street Lateral Phase II Uprate
This enhancement brings lateral capacity to 950,000 therms per day which will meet predicted
growth through 2030. The State Street Phase II Uprate is budgeted for 2026 and is estimated to
cost $1,200,000 direct and $1,085,641 in net present value cost.
Page 98

4.3.5 Sun Valley Lateral
AO1 Summary/System Dynamics
The Sun Valley Lateral (SVL) is a 68-mile-long, 8-inch high pressure pipeline that has almost its
entire demand at the far end of the lateral away from the source of gas. Obtaining land near this
customer load center is either expensive or simply unobtainable. In addition, long sections of
the pipeline are installed in rock that impose construction obstacles for pipeline looping and
expensive construction costs to trench in rock. Throughout the years Intermountain has uprated
and upgraded this existing lateral, installed the Jerome Compressor Station towards the south
end of the lateral and most recently installed the Shoshone Compressor Station to further boosts
pressure and required flows down the lateral to meet the end of line demands on the lateral.The
Shoshone Compressor station was completed in 2023 and is located at mile post 32 which is
approximately 23 miles north of the Jerome Compressor Station.
Capacity Limiter
Due to the significant amount of capital investment with the Shoshone compressor station the
Sun Valley AOI requires no reinforcements to meet 2030 growth predictions.
4.3.6 Idaho Falls Lateral
AO1 Summary/System Dynamics
The Idaho Falls Lateral (IFL) began as a 52 mile, 10-inch pipeline that originated just south of
Pocatello and ended at the city of Idaho Falls. The IFL was later expanded farther to the north
extending an additional 52 miles with 8-inch pipe to serve the growing towns of Rigby, Lewisville,
Rexburg, Sugar City and Saint Anthony. As demand has continually increased along the IFL,
Intermountain Gas has been completing capacity enhancements for the past 25 years; including
compression (now retired), a satellite LNG facility, 40 miles of 12-inch pipeline loop, and 50.5
miles of 16-inch pipeline loops.
Capacity Limiter 2026
Due to continued growth,the IFL AOI requires capacity enhancements by 2026 and 2030 to meet
IRP growth predictions.The current capacity limiter for this AOI is the end of line pressure on the
lateral to St. Anthony's as shown in yellow in Figure 45.
Page 99

iCky
Ilk
Figure 45:Idaho Falls Lateral Capacity Limiter
Capacity Enhancement Alternatives 2026
Two alternatives were considered in the 2021 and 2023 IRPs to address the 2026 predicted
deficit. Those alternatives included a Blackfoot Compressor Station (now called the Wapello
Compressor Station) or a Phase VI 16-inch Pipeline with an additional LNG Tank in Rexburg. The
Wapello Compressor station was chosen in both previous IRPs as the lowest cost option per
therm/day of capacity gained to the lateral.
Capacity Enhancement Selected 2026
The Wapello Compressor enhancement consists of installing a compressor station near Blackfoot,
ID on the Idaho Falls lateral as shown in Figure 46.
Page 100

Shelley
C7
26
Basalt
Sroveland
Alridge
/ Blackfoot
Figure 46:Idaho Falls Lateral Blackfoot Compressor
The selected enhancement brings lateral capacity to 1,037,000 therms per day which would meet
predicted growth through 2029. The compressor has been purchased, and site construction
started in 2025 with planned completion in 2026. Costs are estimated to be $32,520,992 in direct
costs and $34,783,486 in net present value cost.2
Capacity Limiter 2030
Once the Wapello compressor station near Blackfoot is operational, the Idaho Falls Lateral (IFL)
will see increased capacity and pressure downstream of the station. However, modeled growth
predicts that the compressor station's inlet pressures (suction pressures) will drop below
operating parameters in 2030. These lower inlet pressures to the compressor station will reduce
the available gas capacity through the station as it will be operating outside of its design
parameters. The limiting capacity factor on the IFL then becomes the inlet/suction pressures to
the Blackfoot compressor station in 2030.
Z inflated 3.99% each year over the 20-year life of the analysis and a real discount rate of 2.68%
was used in the analysis based on the Company's avoided cost model presented in Exhibit 5—
Avoided Cost Model.
Page 101

Capacity Enhancement Alternatives 2030
Two alternatives were considered to resolve the pressure deficit to the inlet/suction side
pressure to the Wapello compressor. A separate compressor could be installed further upstream
on the lateral to boost pressures to the Wapello compressor or a pipeline loop upstream of the
compressor could be installed to bring available pressure and capacity to the Wapello
compressor.
The first alternative considered was a second compressor on the Idaho Falls Lateral which would
be similar in design and scope to the Wapello compressor with similar costs adjusted for inflation.
The compressor would need to be installed approximately 20 miles south of the existing
compressor near Fort Hall, ID as shown in Figure 47.
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Collins
W Highway 39
Blackfoot
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qi Valley Hic
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--- --_ -- ------ -----------
Figure 47:Idaho Falls Lateral Proposed Compressor Location
Page102

When comparing a compressor to a pipeline, the compressor station will require higher annual
maintenance and operations costs. Examples of these costs would be a compressor operator, oil
to run the compressor, and all the wear parts that will need to be replaced over time.These O&M
costs are included in the NPV cost. A second compressor station would bring lateral capacity to
1,122,000 therms per day at a cost of$46,732,645 in 2030, which has a net present value cost of
$48,359,768.
The second alternative is an 8.5 mile long 16-inch pipeline loop immediately upstream of the
Wapello Compressor, as shown in Figure 48.
1-7
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FIRTH
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GROVELIND
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Figure 48:Idaho Falls Lateral Compressor Suction Proposed Pipeline
This pipeline would bring already available pressure and capacity directly to the suction side of
the new Wapello Compressor.This pipeline loop will bring the capacity of the lateral to 1,122,000
therms per day meeting growth predictions beyond 2030.This alternative will allow the Wapello
compressor to operate within its operational parameters and provide adequate capacity along
the IFL, while avoiding ongoing maintenance and operation costs associated with an additional
compressor station. Costs are estimated to be$42,000,000 in direct costs and $40,240,248 in net
present value cost for this alternative.
Page 103

Capacity Enhancement Selected 2030
Intermountain is considering alternative 2 for the 8 miles of 16-inch pipeline due to lowest cost
alternative when comparing direct and net present value.As discussed above,the operations and
maintenance costs associated with having a second compressor station on the IFL make the
pipeline loop more favorable to meet growth predictions and eliminates the possibility of having
a second compressor station go down during a peak event which could impact the Wapello
compressor station and total IFL capacity.
4.3.7 Other AOI
AOI Summary/System Dynamics
The other AOI is defined as areas outside of IGC's established AOI's. For this IRP IGC has two gate
upgrades that are needed to support core growth and a significant distribution reinforcement.
The two gate upgrades are the State Penn (a.k.a. Boise #3) Gate Upgrade and the New Plymouth
Gate Upgrade. The distribution reinforcement is in Caldwell and will consist of installing
approximately 5 miles of 6-inch plastic pipe on HWY 20 from Prescott Lane (near Can Ada) to
Middleton Road in collaboration with an Idaho Department of Transportation project to widen
Highway 20 to five lanes with several large developments and grocery stores and strip malls
planned for the area. Intermountain will be able to loop its distribution systems and bring gas to
an area that did not have gas with reduced construction costs since the gas line will be installed
in the expanded right of way with minimal restoration and traffic control costs.
Capacity Limiter
Once a gate approaches the physical capacity, its capacity will be limited by undersized piping
and components that will need to be upgraded to increase the capacity of the gate to allow the
gate to be able to meet core growth demand requirements.
Installing infrastructure to a developing area will help offset future deficits since the
infrastructure will be in place and sized for the development expected.
Capacity Enhancement Alternatives
No alternatives to consider for gate upgrades in the small town of New Plymouth. For larger
towns a secondary gate or back feed could be considered as a redundant feed to the town in
comparison to upgrading the existing gate. No alternatives to consider for the State Penn gate
upgrade since only the gate needs to be updated, the surrounding Boise Loop Transmission
infrastructure meets the five year growth demands and does not require reinforcement. Adding
an additional gate would be higher cost since it would also require a pipeline to effectively tie
into the existing high pressure system which would have additional cost to secure land for a new
gate. The higher cost of the pipeline and land considerations justify upgrading the existing gate.
Page 104

No comparable alternatives to consider for a core growth project to loop the distribution system
in an expanding area that needs gas infrastructure with the opportunity for reduced construction
and traffic control cost due to the IDT widening project.
Capacity Enhancement Selected
The New Plymouth Gate upgrade needs to be completed by 2027 to meet core growth needs to
avoid a capacity deficit. The New Plymouth Gate Upgrade is estimated to cost $3,640,000 in
direct and $3,477,264 in net present value cost. The State Penn Gate upgrade needs to be
completed by 2027 to meet core growth needs to avoid a capacity deficit. The capacity gained
for these gate upgrades will depend on the amount contracted in the facility agreement with
Williams Northwest Pipeline. The State Penn Gate Upgrade is estimated to cost $2,980,000 in
direct cost and $2,846,771 in net present value cost. Since the upgraded gate has the same
operations and maintenance costs as the current gate there is not much difference in direct and
net present value since there is no operations and maintenance cost change.
The Caldwell reinforcement will be completed in 2027 based on IDT's construction schedule.The
capacity gained for Caldwell reinforcement is 18,720 therms/day. The Caldwell reinforcement is
estimated at $3,650,000 in direct cost and $3,572,905 in net present value cost.
Page 105

4.3.8 Five-Year Planning and Timing of Capacity Enhancements
To summarize the AOI capacity enhancements below in Table 10 is a capacity summary showing the capacity enhancement selected from
the Company's alternative analysis and corresponding capacity increases.
Ada Coun State Street Lateral Canyon Co n % ' Sun Valley Lateral
M
Idaho Falls Lateral
relected
. . . . . . .f'M W .1� . .. .
Year JJP/
ity
. .
eme
ct
Wapello
State Street Compressor
2026 870,000 None 950,000 Uprate 1,390,000 None 247,500 None 1,037,000 Station
2027 870,000 None 950,000 None 1,390,000 None 247,500 None 1,037,000 None
2028 870,000 None 950,000 None 1,390,000 None 247,500 None 1,037,000 None
2029 870,000 None 950,000 None 1,390,000 None 247,500 None 1,037,000 None
IFL Compressor
Suction
2030 870,000 None 950,000 None 1,390,000 None 247,500 None 1,122,000 Reinforcement
Table 10:AOI Capacity Summary and Timing
As can be seen from table 10, five years is enough time to identify, budget, plan, design and construct projects to address capacity deficits.
As part of the IRP process, Intermountain will check the five-year plan deficits and alternatives considered for capacity enhancement in the
next IRP filing in 2027 and adjust the Company's plans as needed to ensure reliable service to customers based on the next round of IRP
growth predictions. This will be an ongoing iterative process as part of Intermountain's two-year IRP filing.
Page 106

4.4 Load Demand Curves
4.4.1 Overview
The demand forecasting process brings together several key components to create a
comprehensive view of future natural gas needs. This includes customer growth projections,
weather modeling, usage patterns, and demand-side management strategies. Together, these
elements form the foundation of the Load Demand Curve (LDC),which is central to the Integrated
Resource Plan (IRP).The customer forecast extends through Planning Year(PY)2030 and provides
daily projections for the entire Company. It also includes detailed forecasts for five specific Areas
of Interest (AOIs) within the distribution system. Each AOI forecast was developed under three
growth scenarios, low, base case, and high, to account for a range of possible futures.
To model how weather impacts demand, the Company developed a design weather curve that
includes the coldest expected conditions across the service areas.This curve helps estimate daily
usage for residential and commercial customers under peak weather conditions. By combining
this with the customer forecast, Intermountain generates a daily core market load projection
through 2030, both Company-wide and for each AOI. Intermountain also modeled demand under
normal weather conditions for comparison. In addition to residential and commercial customers,
the Company's forecast includes large volume users,those with contract demand that affect both
interstate and local distribution capacity. These figures are integrated with the core market data
to produce a total daily forecast for gas supply and capacity needs, again broken down by AOI.
It's worth noting that the Company's core customers include residential, commercial, and
industrial customers.
The Company then evaluated peak day usage under each growth scenario against current
capacity to identify potential delivery shortfalls. This analysis assists in understanding when and
where constraints might occur, both at the Total Company level and within individual AOIs. Once
the demand forecasts are finalized, the data is then input into PLEXOS°, the optimization
software used by the Company, to support IRP modeling. The LDC captures all relevant factors
influencing future demand and serves as the primary input for long-term planning.
It's important to emphasize that the Load Demand Curves reflect both existing resources and
those confirmed to be available during the forecast period.Their purpose is to highlight potential
capacity constraints and guide strategic planning. Any identified deficits and proposed solutions
will be addressed in the Planning Results section of this report.
Page 107

4.4.2 Customer Growth Summary Observations— Design Weather—All Scenarios
Canyon County Area
Under the low growth scenario, the customer forecast for the Canyon County Area projects an
increase of 11,247 customers, representing a compound annual growth rate (CAGR) of 2.63%. The
base case scenario anticipates an increase of 14,065 customers (3.24%CAGR), while the high growth
scenario projects an increase of 16,970 customers (3.85% CAGR).
Central Ada County
The low growth scenario for Central Ada County forecasts an increase of 5,148 customers, with a
CAGR of 1.34%. The base case projects growth of 7,070 customers (1.82% CAGR), and the high
growth scenario estimates an increase of 9,039 customers (2.30% CAGR).
Sun Valley Lateral
Customer growth in the Sun Valley Lateral under the low growth scenario is projected at 823
customers (1.00% CAGR). The base case scenario forecasts an increase of 1,127 customers (1.36%
CAGR), while the high growth scenario anticipates 1,438 additional customers (1.72% CAGR).
Idaho Falls Lateral
The Idaho Falls Lateral low growth scenario projects an increase of 5,882 customers, reflecting a
CAGR of 1.48%. The base case scenario forecasts growth of 8,641 customers (2.14% CAGR), and the
high growth scenario projects an increase of 11,509 customers (2.80% CAGR).
State Street Lateral
For the State Street Lateral,the low growth scenario forecasts an increase of 5,132 customers(1.34%
CAGR). The base case scenario projects growth of 7,043 customers (1.82% CAGR), while the high
growth scenario anticipates an increase of 9,000 customers (2.29% CAGR).
Total Company
Across the entire service territory,the low growth scenario projects an increase of 37,453 customers,
representing a CAGR of 1.42%. The base case scenario forecasts growth of 52,361 customers (1.96%
CAGR), and the high growth scenario anticipates an increase of 67,712 customers (2.50% CAGR).
These totals include all Areas of Interest (AOIs) as well as customers located outside of the AOIs.
The use of Load Demand Curve (LDC) analyses enables the Company to anticipate changes in future
demand and plan accordingly for the utilization of existing resources and the timely acquisition of
additional capacity. This approach supports long-term reliability and ensures that infrastructure
planning aligns with projected customer growth across all scenarios.
Page 108

4.4.3 Core Distribution Usage Summary— Design and Normal Weather—AII Scenarios
Canyon County Area
Canyon County Design Weather-Annual Core Market Distribution Usage (Dth)
Growth Scenario 2025 2026 2027 2028 2029 2030
Low 9,126,430 9,382,173 9,603,624 9,864,594 10,021,419 10,225,076
Base 9,128,807 9,431,977 9,714,578 10,040,639 10,263,525 10,529,881
High 9,131,170 9,481,762 9,826,252 10,218,781 10,510,634 10,857,701
Table 11: Canyon County Design Weather Annual Usage
Canyon County Normal Weather-Annual Core Market Distribution Usage(Dth)
Growth Scenario 2025 2026 2027 2028 2029 2030
Low 7,203,482 7,402,757 7,575,229 7,779,100 7,902,431 8,062,755
Base 7,205,250 7,441,584 7,661,685 7,916,252 8,091,081 8,305,928
High 7,207,000 7,480,358 7,748,708 8,055,034 8,283,614 8,555,655
Table 12: Canyon County Normal Weather Annual Usage
Central Ada County
Central Ada Design Weather-Annual Core Market Distribution Usage (Dth)
Growth Scenario 2025 2026 2027 2028 2029 2030
Low 8,624,132 8,752,153 8,827,092 8,956,541 9,026,646 9,134,273
Base 8,625,808 8,787,311 8,904,219 9,077,385 9,191,614 9,345,101
High 8,627,479 8,822,437 8,981,745 9,199,433 9,359,063 9,560,341
Table 13: Central Ada Design Weather Annual Usage
Central Ada Normal Weather-Annual Core Market Distribution Usage (Dth)
Growth Scenario 2025 2026 2027 2028 2029 2030
Low 6,804,917 6,904,541 6,963,206 7,063,274 7,118,983 7,202,943
Base 6,806,154 6,931,893 7,023,229 7,157,303 7,247,373 7,367,029
High 6,807,391 6,959,226 7,083,561 7,252,275 7,377,697 7,534,545
Table 14: Central Ada Normal Weather Annual Usage
Page 109

Sun Valley Lateral
Sun Valley Lateral Design Weather-Annual Core Market Distribution Usage(Dth)
Growth Scenario 2025 2026 2027 2028 2029 2030
Low 2,662,285 2,683,948 2,703,638 2,737,314 2,742,888 2,762,692
Base 2,662,860 2,694,135 2,725,728 2,771,424 2,788,868 2,820,997
High 2,663,470 2,704,337 2,747,700 2,805,872 2,835,715 2,880,627
Table 1 S: Sun Valley Lateral Design Weather Annual Usage
Sun Valley Lateral Normal Weather-Annual Core Market Distribution Usage(Dth)
Growth Scenario 2025 2026 2027 2028 2029 2030
Low 2,268,361 2,286,586 2,303,129 2,330,316 2,336,105 2,352,741
Base 2,268,821 2,295,196 2,321,849 2,359,236 2,375,125 2,402,223
IHigh 2,269,298 2,303,815 2,340,471 2,388,436 2,414,871 2,452,831
Table 16: Sun Valley Lateral Normal Weather Annual Usage
Idaho Falls Lateral
Idaho
Growth Scenario 2025 2026 2027 2028 2029 2030
Low 9,259,159 9,379,303 9,490,022 9,648,006 9,707,113 9,811,125
Base 9,262,382 9,437,748 9,617,474 9,847,674 9,979,185 10,158,768
High 9,265,643 9,496,037 9,745,908 10,050,920 10,258,645 10,519,037
Table 17:Idaho Falls Lateral Design Weather Annual Usage
Idaho Falls Lateral Normal Weather-Annual Core Market Distribution Usage (Dth)
Growth Scenario 2025 2026 2027 2028 2029 2030
Low 8,145,753 8,249,900 8,346,202 8,479,886 8,534,958 8,625,383
Base 8,148,652 8,301,066 8,457,454 8,653,957 8,772,206 8,928,473
High 8,151,578 8,352,049 8,569,583 8,831,177 9,015,898 9,242,549
Table 18:Idaho Falls Lateral Normal Weather Annual Usage
Page110

N. of State Street Lateral
N. of State Street Lateral Design Weather-Annual Core Market Distribution Usage (Dth)
Growth Scenario 2025 2026 2027 2028 2029 2030
Low 8,724,715 8,855,421 8,933,661 9,066,966 9,139,106 9,249,526
Base 8,726,430 8,891,197 9,012,117 9,189,883 9,306,886 9,463,920
High 8,728,141 8,926,937 9,090,984 9,314,021 9,477,171 9,682,781
Table 19:N. of State Street Lateral Design Weather Annual Usage
N. of State Street Lateral Normal Weather-Annual Core Market Distribution Usage (Dth)
Growth Scenario 2025 2026 2027 2028 2029 2030
Low 6,853,813 6,955,629 7,016,960 7,120,011 7,177,515 7,263,746
Base 6,855,083 6,983,490 7,078,076 7,215,742 7,308,212 7,430,757
High 6,856,354 7,011,330 7,139,510 7,312,429 7,440,864 7,601,243
Table 20:N. of State Street Lateral Normal Weather Annual Usage
Total Company
Total Company Design Weather-Annual Core Market Distribution Usage (Dth)
Growth Scenario 2025 2026 2027 2028 2029 2030
Low 61,337,023 62,202,500 62,842,356 63,815,062 64,235,964 64,942,077
Base 61,352,608 62,508,305 63,512,390 64,864,574 65,666,460 66,761,430
High 61,368,264 62,813,946 64,186,553 65,928,323 67,126,374 68,646,400
Table 21: Total Company Design Weather Annual Usage
Total Company Normal Weather-Annual Core Market Distribution Usage (Dth)
Growth Scenario 2025 2026 2027 2028 2029 2030
Low 50,342,560 51,042,762 51,560,865 52,340,833 52,689,865 53,262,400
Base 50,354,834 51,291,129 52,104,753 53,192,410 53,850,764 54,744,689
High 50,367,142 51,539,274 52,651,980 54,055,590 55,035,525 56,268,357
Table 22: Total Company Normal Weather Annual Usage
Page111

4.4.4 Projected Capacity Deficits — Design Weather—All Scenarios
Over the planning horizon, peak day load on Intermountain's system is projected to grow at a compound
annual growth rate (CAGR)of 1.12% under the low growth scenario, 1.46% in the base case, and 1.86%
under the high growth scenario.The following section outlines anticipated capacity deficits across each Area
of Interest(AOI) and for the company as a whole.
Canyon County Area LDC Study
Forecasted peak day usage for the Canyon County Area remains within the maximum physical deliverability
of 139,000 dekatherms (Dth) across all customer growth scenarios. No peak day deficits are projected,
indicating that available capacity is sufficient to meet anticipated demand throughout the forecast period.
Canyon County Design Weather- Peak Day Deficit Under Existing Resources(Dth)
Growth Scenario 2025 2026 2027 2028 2029 2030
Low 0 0 0 0 0 0
Base 0 0 0 0 0 0
High 0 0 0 0 0 0
Table 23: Canyon County Design Day Deficit
Central Ada County LDC Study
Forecasted peak day usage for Central Ada County remains within the maximum physical deliverability of
87,000 dekatherms(Dth) across all customer growth scenarios. No peak day deficits are projected,
indicating that available infrastructure is sufficient to meet anticipated demand throughout the forecast
horizon.
Central Ada Design Weather- Peak Day Deficit Under Existing Resources(Dth)
Growth Scenario 2025 2026 2027 2028 2029 2030
Low 0 0 0 0 0 0
Base 0 0 0 0 0 0
High 0 0 0 0 0 0
Table 24: Central Ada Design Day Deficit
Page 112

Sun Valley Lateral LDC Study
Forecasted peak day usage on the Sun Valley Lateral remains within the maximum physical deliverability of
24,750 dekatherms(Dth) under all customer growth scenarios. As a result, no peak day deficits are
projected for this lateral, indicating sufficient capacity to meet anticipated demand across the forecast
period.
Sun Valley Lateral Design Weather- Peak Day Deficit Under Existing Resources(Dth)
Growth Scenario 2025 2026 2027 2028 2029 2030
Low 0 0 0 0 0 0
Base 0 0 0 0 0 0
High 0 0 0 0 0 0
Table 25: Sun Valley Lateral Design Day Deficit
Idaho Falls Lateral LDC Study
When forecasted peak day usage in the Idaho Falls Lateral is compared to the maximum physical
deliverability of 103,700 dekatherms (Dth), no peak day deficits are projected under any of the customer
growth scenarios.This outcome is attributed to the planned upgrade of the Wapello Compressor Station,
which is expected to be operational in 2026.The enhancement ensures sufficient capacity to meet
anticipated demand across all modeled scenarios.
Idaho Falls Lateral Design Weather-Peak Day Deficit Under Existing Resources(Dth)
Growth Scenario 2025 2026 2027 2028 2029 2030
Low 0 0 0 0 0 0
Base 0 0 0 0 0 0
High 0 0 0 0 0 0
Table 26:Idaho Falls Lateral Design Day Deficit
Page 113

N. of State Street Lateral LDC Study
Forecasted peak day usage for the State Street Lateral remains within the maximum physical deliverability of
95,000 dekatherms(Dth) across all scenarios due to planned upgrades.These planned infrastructure
upgrades for this AOI are outlined in the Capacity Enhancements section.
N. of State Street Design Weather- Peak Day Deficit UnderResources
Growth Scenario 2025 2026 2027 2028 2029 2030
Low 0 0 0 0 0 0
Base 0 0 0 0 0 0
High 0 0 0 0 0 0
Table 27:N. of State Street Design Day Deficit
Total Company LDC Study
The Total Company perspective reflects the volume of gas that can be delivered to Intermountain through
available interstate resources, rather than the capacity of individual laterals or Areas of Interest.Total
system deliveries must be sufficient to meet the combined demand—or available distribution capacity,
where applicable—across all Areas of Interest. Projected peak day deficits are summarized in the following
table, with mitigation strategies discussed in the Upstream Modeling Results section of the Planning Results.
Total • Day Deficit Under Existing Resources
Growth Scenario 2025 2026 2027 2028 2029 2030
Low 0 0 5,462 11,404 17,858 24,175
Base 0 2,258 11,194 20,466 30,351 40,167
High 0 4,758 16,962 29,642 43,090 56,640
Table 28: Total Company Design Day Deficit
Page 114

4.4.5 2023 IRP vs. 2025 IRP Common Year Comparisons
This section provides a comparison between the Total Company and each AOI across the three common
years included in both the 2023 and 2025 IRP filings.Variations between the two filings may be attributed to
several factors, including refinements in modeling techniques and the incorporation of newly available data
used to enhance model accuracy and reliability.
Total Company Design Weather Base Case Growth Comparison
2025 IRP LOAD DEMAND CURVE
TOTAL • DAY USAGE
DESIGN WEATHER—BASE CASE (Dth)
Core Market Firm CD1 Total
2026 529,083 173,444 702,526
2027 538,019 173,744 711,762
2028 547,271 174,484 721,754
IlExisting firm contract demand includes LV-1 and T-4 requirements.
Table 29: 2025 IRP Total Company Design Day Peak Usage
2023 IRP LOAD DEMAND CURVE
TOTAL • DAY USAGE
DESIGN WEATHER—BASE CASE (Dth)
Core Market Firm CD1 Total
2026 515,575 151,064 666,639
2027 526,915 151,704 678,619
2028 538,255 151,774 690,029
lExisting firm contract demand includes LV-1 and T-4 requirements.
Table 30: 2023 IRP Total Company Design Day Peak Usage
Page115

2025 IRP LOAD
TOTAL COMPANY . DAY USAGE
DESIGN WEATHER—BASE CASE (Dth)
• 2023 IRP
Core Market Firm CD1 Total
2026 13,508 22,380 35,887
2027 11,104 22,040 33,143
2028 9,016 22,710 31,725
'Existing firm contract demand includes LV-1 and T-4 requirements.
Table 31: 2023 IRP vs. 2025 IRP Total Company Design Day Peak Usage
Total Company Peak Day Deliverability Comparison
2025 IRP PEAK DAY STORAGE
Maximum Daily Storage Withdrawals: 2026 2027 2028
Nampa LNG 50,000 50,000 50,000
Plymouth LS 155,175 155,175 155,175
Jackson Prairie SGS 30,337 30,337 30,337
Total Storage 235,512 235,512 235,512
Maximum Deliverability(NWP) 293,893 293,893 293,893
Total Peak Day Deliverability 529,405 529,405 529,405
Table 32: 2025 IRP Total Company Storage Deliverability
Page116

2023 IRP PEAK DAY FIRM STORAGE
Maximum Daily Storage Withdrawals: 2026 2027 2028
Nampa LNG 60,000 60,000 60,000
Plymouth LS 155,175 155,175 155,175
Jackson Prairie SGS 30,337 30,337 30,337
Total Storage 245,512 245,512 245,512
Maximum Deliverability(NWP) 290,893 290,893 290,893
Total Peak Day Deliverability 536,405 536,405 536,405
Table 33: 2023 IRP Total Company Storage Deliverability
2025 IRP PEAK DAY FIRM STORAGE DELIVERY CAPABILITY(Dth)
Over/(Under)2023 IRP
Maximum Daily Storage Withdrawals: 2026 2027 2028
Nampa LNG (10,000) (10,000) (10,000)
Plymouth LS 0 0 0
Jackson Prairie SGS 0 0 0
Total Storage (10,000) (10,000) (10,000)
Maximum Deliverability(NWP) 3,000 3,000 3,000
Total Peak Day Deliverability (7,000) (7,000) (7,000)
Table 34: 2023 IRP vs. 2025 IRP Total Company Storage Deliverability
Page117

Canyon County Area Design Weather/ Base Case Growth Comparison
LOAD DEMAND CURVE
CANYON • DAY USAGE
DESIGN WEATHER—BASE CASE (Dth)
Peak Day Usage
Maximum Physical
Deliverability Core Market Firm CD1 Total
2026 139,000 83,935 25,160 109,095
2027 139,000 86,567 25,360 111,927 I
2028 139,000 89,107 25,380 114,487
'Existing firm contract demand includes LV-1 and T-4 requirements.
Table 35: 2025 IRP Canyon County Design Weather and Physical Deliverability
2023 IRP LOAD DEMAND CURVE
CANYON • DAY USAGE
DESIGN WEATHER—BASE CASE(Dth)
Peak Day Usage
Maximum Physical
Deliverability Core Market Firm CD1 Total
2026 139,000 85,370 25,110 110,480
2027 139,000 88,270 25,110 113,380 I
2028 139,000 91,171 25,130 116,301
'Existing firm contract demand includes LV-1 and T-4 requirements.
Table 36: 2023 IRP Canyon County Design Weather and Physical Deliverability
Page118

2025 IRP LOAD
CANYON • DELIVERABILITY& PEAK DAY USAGE
DESIGN WEATHER—BASE CASE(Dth)
• 2023 IRP
Peak Day Usage
Maximum Physical
Deliverability Core Market Firm CD1 Total
2026 (1,435) 50 (1,385)
2027 - (1,703) 250 (1,453)
2028 - (2,064) 250 (1,814)
IExisting firm contract demand includes LV-1 and T-4 requirements. I
Table 37: 2023 IRP vs. 2025 IRP Canyon County Design Weather and Physical Deliverability
Page119

Central Ada County Design Weather/ Base Case Growth Comparison
LOAD DEMAND CURVE
CENTRAL .D. MAXIMUM PHYSICAL DELIVERABILITY& PEAK DAY USAGE
DESIGN WEATHER—BASE CASE (Dth)
Peak Day Usage
Maximum Physical
Deliverability Core Market Firm CD1 Total
2026 87,000 78,347 850 79,197
2027 87,000 79,417 850 80,267 I
2028 87,000 80,622 850 81,472
'Existing firm contract demand includes LV-1 and T-4 requirements.
Table 38: 2025 IRP Central Ada Design Weather and Physical Deliverability
2023 IRP LOAD
CENTRAL ADA MAXIMUM PHYSICAL DELIVERABILITY& PEAK DAY USAGE
DESIGN WEATHER—BASE CASE (Dth)
Peak Day Usage
Maximum Physical
Deliverability Core Market Firm CD1 Total
2026 87,000 76,914 850 77,764
2027 87,000 78,501 850 79,351 I
2028 87,000 80,088 850 80,938
'Existing firm contract demand includes LV-1 and T-4 requirements.
Table 39: 2023 IRP Central Ada Design Weather and Physical Deliverability
Page120

2025 IRP LOAD DEMAND
CENTRAL . I . MAXIMUM PHYSICALDELIVERABILITY& PEAK DAY
DESIGN WEATHER—BASE CASE(Dth)
• . 2023 IRP
Peak Day Usage
Maximum Physical
Deliverability Core Market Firm CD1 Total
2026 - 1,433 11433
2027 - 916 916 I
2028 - 534 - 534
'Existing firm contract demand includes LV-1 and T-4 requirements.
Table 40: 2023 IRP vs. 2025 IRP Central Ada Design Weather and Physical Deliverability
Sun Valley Lateral Design Weather/ Base Case Growth Comparison
2025 IRP LOAD DEMAND CURVE
SUN VALLEY LATERAL MAXIMUM PHYSICAL DELIVERABILITY& PEAK DAY
DESIGN WEATHER—BASE CASE(Dth)
Peak Day Usage
Maximum Physical
Deliverability Core Market Firm CD1 Total
2026 24,750 20,349 1,935 22,284
2027 24,750 20,599 1,935 22,534
2028 24,750 20,848 1,935 22,783
'Existing firm contract demand includes LV-1 and T-4 requirements.
Table 41: 2025 IRP Sun Valley Lateral Design Weather and Physical Deliverability
Page121

2023 IRP" LOAD
PHYSICALSUN VALLEY LATERAL MAXIMUM DELIVER.;DELIVERABILITY& PEAKDAY USAGE
DESIGN WEATHER—BASE CASE (Dth)
Peak Day Usage
Maximum Physical
Deliverability Core Market Firm CD1 Total
2026 24,750 18,613 1,935 20,548
2027 24,750 18,868 1,935 20,803 I
2028 24,750 19,123 1,935 21,058
'Existing firm contract demand includes LV-1 and T-4 requirements.
Table 42: 2023 IRP Sun Valley Lateral Design Weather and Physical Deliverability
2025 IRP LOAD
SUN VALLEY LATERAL MAXIMUM PHYSICAL DELIVERABILITY& PEAK DAY
DESIGN WEATHER—BASE CASE(Dth)
• . 2023 IRP
Peak Day Usage
Maximum Physical
Deliverability Core Market Firm CD1 Total
2026 - 1,736 1,736
2027 - 1,731 1,731
2028 I - 1,725 - 1,725
I 'Existing firm contract demand includes LV-1 and T-4 requirements. I
Table 43: 2023 IRP vs. 2025 IRP Sun Valley Lateral Design Weather and Physical Deliverability
Page122

Idaho Falls Lateral Design Weather/Base Case Growth Comparison
2025 IRP LOAD DEMAND CURVE
D. • FALLS LATERAL MAXIMUM PHYSICAL DELIVERABILITY& PEAK DAY USAGE
DESIGN WEATHER—BASE CASE (Dth)
Peak Day Usage
Maximum Physical
Deliverability Core Market Firm CD1 Total
2026 103,700 73,541 20,241 93,782
2027 103,700 75,045 20,341 95,386 I
2028 103,700 76,566 20,341 96,907
'Existing firm contract demand includes LV-1 and T-4 requirements.
Table 44: 2025 IRP Idaho Falls Lateral Design Weather and Physical Deliverability
LOAD DEMAND CURVE
D. • FALLS LATERAL MAXIMUM PHYSICAL DELIVERABILITY& PEAK DAY USAGE
DESIGN WEATHER—BASE CASE (Dth)
Peak Day Usage
Maximum Physical
Deliverability Core Market Firm CD1 Total
2026 109,300 69,823 20,301 90,124
2027 109,300 71,529 20,341 91,870 I
2028 109,300 73,233 20,341 93,574
'Existing firm contract demand includes LV-1 and T-4 requirements.
Table 45: 2023 IRP Idaho Falls Lateral Design Weather and Physical Deliverability
Page 123

2025 IRP LOAD
IDAHO FALLS LATERAL MAXIMUM PHYSICAL DELIVERABILITY& PEAK DAY USAGE
DESIGN WEATHER-BASE CASE(Dth)
• 2023 IRP
Peak Day Usage
Maximum Physical
Deliverability Core Market Firm CD1 Total
2026 (5,600) 3,718 (60) 3,658
2027 (5,600) 3,516 - 3,516 I
2028 (5,600) 3,333 - 3,333
'Existing firm contract demand includes LV-1 and T-4 requirements.
Table 46: 2023 IRP vs. 2025 IRP Idaho Falls Lateral Design Weather and Physical Deliverability
N. of State Street Lateral Design Weather/ Base Case Growth Comparison
2025 IRP LOAD DEMAND CURVE
N. of STATE STREET LATERAL MAXIMUM PHYSICAL DELIVERABILITY& PEAK DAY USAGE
DESIGN WEATHER-BASE CASE 1
Peak Day Usage
Maximum Physical
Deliverability Core Market Firm CD1 Total
2026 95,000 80,657 1,190 81,847 I
2027 95,000 81,761 1,190 82,951 I
2028 95,000 82,999 1,190 84,189 I
'Existing firm contract demand includes LV-1 and T-4 requirements. I
Table 47: 2025 IRP N. of State Street Lateral Design Weather and Physical Deliverability
Page124

2023 IRP" LOAD DEMAND CURVE
PHYSICALN. of STATE STREET LATERAL MAXIMUM DELIVER.;DELIVERABILITY& PEAKDAY USAGE
DESIGN WEATHER—BASE CASE (Dth)
Peak Day Usage
Maximum Physical
Deliverability Core Market Firm CD1 Total
2026 95,000 79,163 990 80,153
2027 95,000 80,762 990 81,752 I
2028 95,000 82,362 990 83,352
'Existing firm contract demand includes LV-1 and T-4 requirements.
Table 48: 2023 IRP N. of State Street Lateral Design Weather and Physical Deliverability
2025 IRP LOAD
N. of STATE STREET LATERAL MAXIMUMPHYSICAL DELIVER.DELIVERABILITY& PEAK DAY
DESIGN WEATHER—BASE CASE(Dth)
•ver/(Under) 2023 IRP
Peak Day Usage
Maximum Physical
Deliverability Core Market Firm CD1 Total
2026 - 1,494 200 1,694
2027 - 999 200 1,199
2028 ' - 637 200 837
I 'Existing firm contract demand includes LV-1 and T-4 requirements. I
Table 49: 2023 IRP vs. 2025 IRP N. of State Street Lateral Design Weather and Physical Deliverability
Page125

4.5 Resource Optimization
4.5.1 Introduction
Intermountain's IRP utilizes an optimization model that selects resource amounts over a pre-
determined planning horizon to meet forecasted loads by minimizing the present value of
resource costs. The model evaluates and selects the least cost mix of supply and transportation
resources utilizing a standard mathematical technique called linear programming. Essentially,the
model integrates/coordinates all the individual functional components of the IRP such as
demand, supply, demand side management, transport and supply into a least cost mix of
resources that meet demands over the IRP planning horizon, 2025 to 2030.
This section of the IRP will describe the functional components of the model,the model structure
and its assumptions in general. At the end, model results will be discussed.
4.5.2 Functional Components of the Model
The optimization model has the following functional components:
• Demand Forecast by AOI
• Supply Resources, Storage and Supply, by Area
• Transportation Capacity Resources, Local Laterals and Major Pipelines, Between Areas
• Non-Traditional Resources such as Renewable Natural Gas
• Demand Side Management
Underlying these functional components is a model structure that has gas supply and demand by
area of interest with gas transported by major pipelines and local distribution laterals between
supply and demand. This model mirrors, in general, how Intermountain's delivery system
contractually and operationally functions. In previous IRPs, Intermountain utilized Boris Metrics
to perform the optimization modeling. Beginning with the 2023 IRP, the Company is utilizing its
in-house expertise to perform the optimization modeling to streamline processes. The
optimization modeling results have yielded comparable results.
4.5.3 PLEXOS° Optimization Model
Resource integration is one of the final steps in Intermountain's IRP process. It involves finding
the reasonable least cost and least risk mix of reliable demand and supply side resources to serve
the forecasted load requirements of the core customers. The tool used to accomplish this task in
the IRPs prior to 2023 was a computer optimization model known as SENDOUT°. In this IRP,
Intermountain is utilizing PLEXOS°, which is a very similar model to SENDOUT°.
Page 126

PLEXOS° is very powerful and complex. It operates by combining a series of existing and potential
demand side and supply side resources and optimizing their utilization at the lowest net present
cost over the entire planning period for a given demand forecast. PLEXOS° permits the Company
to develop and analyze a variety of resource portfolios quickly and to determine the type, size,
and timing of resources best matched to forecast requirements.
4.5.4 Model Structure
To develop a basic understanding of how gas supply flows from the various receipt points to
ultimate delivery to the Company's end-use customers, a graphical representation of
Intermountain's system is helpful. Figure 2 (page 6) is a map of the Intermountain system.
Generally, gas flows from supply areas such as Canada and the Rockies, and from storage in
Washington state and Clay Basin in the Rockies region, across major pipelines to southern Idaho.
In southern Idaho, the gas is transported to demand areas by local distribution laterals. The
model utilizes a simplified structure of the Figure 2 map.
Figure 58 presents the model of system flows by major pipelines and supply areas. The Figure
also shows four major supply receipt areas including Sumas, Stanfield, AECO and Rockies with
ultimate delivery to Intermountain in southern Idaho.
Page 127

,r
'•. algary
7`
AB/C 1 '
•Van uver
!� 4
Sumas Kingsgate
tle
ane
T coma WA INGTON MO
Helena
1P!C
Portland
PLY 3 ` `,7. f •.R
4em "1 t
,gene OREGON
M - Street NC Sun Vall NC
ley
Nampa Idaho Falls NC
_-.... ..kda NC
+- IGC Rexburg NC i
r -- -- --'---- - ---- - - - - +i
Opal
.` GrcaLSal! Clay IC
Figure 49:IGC Natural Gas Modeling System Map
Supplies from the supply receipt areas are then delivered and aggregated at the IGC pool (Zone
24) where they are allocated to be delivered to the appropriate demand areas, or AOIs, by local
distribution laterals as depicted in Figure 49.
Page 128

4.5.5 Demand Area Forecasts
As previously discussed in the Load Demand Curves Section, demand is forecasted using a unique
load demand curve for each AOI. The sum of all six areas is equal to system gas demand. A map
of the AOIs is included at the end of the Executive Summary. Intermountain forecasts peak
demand to be 518,606 dth for RS (Residential) and GS (commercial) customers and 161,014 dth
for LV-1 and T-4 customers in 2025 and growing to 566,971 dth and 174,484 dth in 2030,
respectively.
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . Rexburg . . . . . . . . . . . . . .
r • ` .
Idaho Falls-core Idaho Falls Idaho Falls NC`Idaho Falls-non core
. .
. . . . . . . . . . V • �. . . . . . . .
Sun Valley-core ' Sun Valley Sun Valley INC Sun Valley-non core . . . . . .
a
-� All Other-core All Other. . .All Other NC : All Other-non core
`'
92
IGC .,i ` . a ^ . IGC NC '
Central Ada-core ' Central Ada Central Ada NC Central Ada-non core
Canyon County-core anyon County Canyon County NC l Canyon County-non core
. . . . \ . . . . . . . . . . . . .
`\ ` . - ` vi
State Street-core"I N State Street N State Street NC State Street-non core
. . . . . . . . . . . . . . . . . . .
Figure 50:IGC Laterals from Zone 24
The demand areas listed in Figure 50 are:
• Central Ada Area
• State Street Lateral
• Canyon County Region
• Idaho Falls Lateral
• Sun Valley Lateral
• All Other
Page 129

2025 Load Demand Curve
Design Base Case
Total Company
700,000
600000 Peak Day 536,800 Dth
500,000
— — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — —
400,000
L
300,000
200,000
100,000
t�
10/1/2025 11/1/2025 12/1/2025 1/1/2026 2/1/2026 3/1/2026 4/1/2026 5/1/2026 6/1/2026 7/1/2026 8/1/2026 9/1/2026
Core+LV-1 Demand less DSM — —Maximum Transport Deliverability with LNG — —Maximum Transport Deliverability
Figure 51: 2025 LDC Total Company Design Weather Base Case
The model is also programmed to recognize that Intermountain must provide gas supply and
both interstate and distribution transportation for its core market and LV-1 customers, but only
firm distribution capacity for T-4 customers. Figure 51 shows the core market demand with LV-1
customers less DSM, compared to the maximum upstream distribution Intermountain has to
serve the demand. T-3 customers are served on an interruptible basis and therefore are not
included in the analysis. Because Intermountain is contractually obligated to provide a certain
level of firm transport capacity for its firm transporters each day, the industrial demand forecast
for these customers is not load-shaped but reflects the aggregate firm industrial CD for each class
by specific AOI for each period in the demand curve.
Scenarios forthe load demand curves include specific weather and customer growth assumptions
which are described elsewhere in this IRP.The weather scenarios are normal weather and design
weather. Customer growth is separated into low growth, base case and high growth scenarios.
This results in a total of six scenarios. The combination of the design weather and base case
scenarios(Design Base)form the critical planning scenario for the IRP and will be reported as the
main optimization results. Other scenarios are also available, but all others, except for the
combined scenarios of design weather and high growth, would have sufficient resources as long
as the Design Base does.
Page 130

4.5.6 Supply Resources
Resource options for the model are of two types: supply resources and storage contracts,which,
from a modeling standpoint, are utilized in a similar manner. All resources have beginning and
ending years of availability, periods of availability, must take usage, period and annual flow
capability and a peak day capability. Supply resources have price/cost information entered in the
model over all points on the load demand curve for the study period. Additionally, information
relating to storage resources includes injection period, injection rate, fuel losses and other
storage related parameters.
Each resource must be sourced from a specific receipt point or supply area. For example, Figure
52 shows the supply area (in green) providing gas at the AECO interconnect. One advantage of
citygate supplies and certain storage withdrawals is that they do not utilize any of
Intermountain's existing interstate capacity as the resource is either sited within a demand area
or are bundled with their own specific redelivery capacity. Supply resources from British
Columbia are delivered into the NWP system at Sumas while Rockies supplies are received from
receipt pools known as North of Green River and South of Green River. Alberta supplies are
delivered to Northwest's Stanfield interconnect utilizing available upstream capacity - the
available quantity at Stanfield is the limiting factor regardless of capacity of any single upstream
pipeline. Each supply resource utilizes transport that reaches Zone 24 from its supply receipt
node.
16 . .
. . AECO . . . . . .
Figure 52:IGC Supply Model Example
Page 131

PLY
PLY 3
. �+. ` .
PLY IC
Figure 53:IGC Storage Model Example
Figure 53 shows an example of the PLEXOS modeling perspective of Storage contracts connected
to the rest of the system. From a model perspective, the DSM resources are considered a subset
of supply resources and fill demand needs on the applicable AOI by offsetting other supply
resources when the cost of such is less than other available resources. The DSM applied directly
to the AOL These DSM resources have costs and resource capacity that were determined by a
separate DSM analysis as detailed in the Core Market Energy Efficiency Section.
Page 132

4.5.7 Transport Resources
Transport resources represent the way supplies flow from specific receipt areas to
Intermountain's ultimate receipt pool at Zone 24, where all supplies are pooled for ultimate
delivery into the Company's various Areas of Interest. Transport resources reflect contracts for
interstate capacity, primarily on Northwest Pipeline, but also for the three separate pipelines that
deliver gas supplies to Northwest's Stanfield interconnect from AECO. Certain supplies, such as
Rexburg LNG, are already located on Intermountain's distribution system on a specific demand
lateral and therefore do not require interstate pipeline transportation. The system
representation recognizes Northwest's postage stamp pricing and capacity release as well as the
per mile rates seen on the transportation contracts from AECO to Stanfield.
Transport resources have a peak day capability and are assumed to be available year-round unless
otherwise noted. Transport resources can have different cost and capabilities assigned to them
as well as different years of availability. An example of a transportation model is seen in Figure
54.
. . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . �.
Mco
. . . . . . . . .
. . . . . . . . . . . . . . . .
. . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . .
. . . . • . . . • • . . . . .
. . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . .
. . . . . . . . . . . .
Figure 54:IGC Transport Model Example
4.5.8 Model Operation
The selection of a least cost mix of resources, or resource optimization, is based on the cost,
availability and capability of the available resources as compared to the projected loads at each
of the AOIs. The model chooses the mix of resources which meet the optimization goal of
minimizing the present value cost of delivering gas supply to meet customer demand. The model
recognizes contractual take commitments and all resources are evaluated for reasonableness
prior to input. Both the fixed and variable costs of transport, storage and supply can be included.
The model will exclude resources it deems too expensive compared to other available
alternatives.
Page 133

The model can treat fixed costs as sunk costs for certain resources already under contract. If a
fixed cost or annual cost is entered for a resource, the model can include that cost for the
resource in the selection process, if directed, which will influence its inclusion vis-a-vis other
available resources. If certain resources are committed to and the associated fixed cost will be
paid regardless of the level of usage, only the variable cost of that resource is considered during
the selection process, but the fixed cost is included in the summary. However, any new resources,
which would be additional to the resource mix, will be evaluated using both fixed and variable
costs. For cost summary purposes, fixed costs were included, whether sunk or included in the
least cost present value optimization, to approximate the expected total costs for transport and
supply.
4.5.9 Special Constraints
As stated earlier,the model minimizes cost while satisfying demand and operational constraints.
Several constraints specific to Intermountain's system were modeled.
• Nampa LNG storage does not require redelivery transport capacity. Both SGS and LS storage
are bundled with firm redelivery capacity;transportation utilization of this capacity matches
storage withdrawal from these facilities. SGS, LS and Clay Basin refills are typically injected
in the summer.
• All core market and LV-1 sales loads are completely bundled.
• T-4 customer transportation requirements utilize only Intermountain's distribution capacity.
The T-4 firm CD is input as a no-cost supply delivered at Zone 24. T-3 customers are served
on an interruptible basis and therefore not included in the analysis.
• Traditional resources destined fora specific AOI must be first transported to Zone 24 and then
to the AOI.
• Non-traditional resources such as mobile LNG that are designed to serve a specific lateral can
only be employed when lateral capacity is otherwise fully utilized.
4.5.10 Model Inputs
The optimization model utilizes these three inputs which do not vary by scenario:
• Transport Resources
• Supply Resources by Year
• Supply Price Format for Supply Resources by Yearly Periods
The model selects the best cost portfolio based on least cost of present value resource costs over
the planning horizon. However, the model also has been designed to comply with operational
and contractual constraints that exist in the real world (i.e. if the most inexpensive supply is
located at Sumas, the model can only take as much as can be transported from that point;
Page 134

additionally, it will not take inexpensive spot gas until all constraints related to term gas or
storage are fulfilled). For the results to provide a reasonable representation of actual operations,
all existing resources that have committed must-take contracts are assigned as "must run"
resources. The Company's minimal commitment for summer must-take supplies means that
those supplies do not exceed demand. In the real world, having excess summer supplies results
in selling those volumes into the market at the then prevailing prices whereas the model only
identifies those volumes and related cost. Please note that this level of sales is small relative to
total supply.
Another important assumption relates to the supply fill or balancing options.Supply fill resources
provide intelligence as to where and how much of any deficit in any existing resource exists. The
model treats these resources as economic commodities (i.e. the availability is dynamic up to its
maximum capability). The model can select available fill supply at any basin, for any period and
in any volume that it needs to help fill capacity constraints. To ensure that the model provides
results that mirror reality,these supplies have been aggregated into peak,winter(base and day),
summer (base and day) and annual price periods. Base gas is typically a longer-term contract
than day gas. Each aggregated group has a different relative price with the peak price being the
highest,and the summer price beingthe lowest.Additionally,since term pricing is normally based
on the monthly spot index price, no attempt has been made to develop fixed pricing for fill
resources, but each such resource includes a reasonable market premium if applicable.
All transport resources are labeled to specify the pipeline as well as a contract number associated
with the transport contract in the Transport table in Exhibit 8. Capability and pricing are included
by resource. Figure 55 provides a sample of the input information provided in Exhibit 8.The main
inputs for each transportation contract are provided. This includes the Monthly Daily Quantity
(MDQ), D1 rate, Transportation Rate, and Fuel percentage. The MDQ is the contract's specific
maximum allowable gas in dekatherms the Company can transport on a given day. The D1 rate
is the reservation rate for the transport contract. The transportation rate is the rate charged to
the volumes flowed if the pipeline was utilized for the day. The fuel loss percentage is the
statutory percent of gas based on the tariff from the pipeline that is lost and unaccounted for
from the point of where the gas was purchased to the delivery point.
Page 135

Transport Name Property Oct-24 Nov-24 Dec-24 Jan-25 Feb-25 Mar-25
FTHLS 1 Max Daily Flow(BBtu) 7.105 7.105 7.105 7.105 7.105 7.105
FTHLS 1 Reservation Cost($/MMBtu) $ 2.82 $ 2.73 $ 2.82 $ 2.82 $ 2.55 $ 2.82
FTHLS 1 Loss(BBtu) 0.000 0.000 0.000 0.000 0.000 0.000
FTHLS 1 Total Variable Costs($/MMBtu) $ - $ - $ - $ - $ - $ -
FTHLS 2 Max Daily Flow(BBtu) 87.639 87.639 87.639 87.639 87.639 87.639
FTHLS 2 Reservation Cost($/MMBtu) $ 2.82 $ 2.73 $ 2.82 $ 2.82 $ 2.55 $ 2.82
FTHLS 2 Loss(BBtu) 0.000 0.000 0.000 0.000 0.000 0.000
FTHLS 2 Total Variable Costs($/MMBtu) $ - $ - $ - $ - $ - $ -
FTHLS 3 Max Daily Flow(BBtu) 0.000 20.941 20.941 20.941 20.941 20.941
FTHLS 3 Reservation Cost($/MMBtu) $ - $ 2.73 $ 2.82 $ 2.82 $ 2.55 $ 2.82
FTHLS 3 Loss(BBtu) 0.000 0.000 0.000 0.000 0.000 0.000
FTHLS 3 Total Variable Costs($/MMBtu) $ - $ - $ - $ - $ - $ -
Figure SS: Transport Input Summary
The price forecast is provided in the Traditional Supply Resources section.
4.5.11 Model Results
The optimization model results for the design weather, base price and base case scenario for the
years 2025 through 2030 are presented and discussed below. The results of the model are
summarized, for each scenario using the tables described below:
• Upstream Transportation and Lateral Summary Tables (Exhibit 9)
• Annual Transportation Resources Results (Exhibit 8)
• Annual Supply Resources Results (Exhibit 8)
Model Output for Design Base Scenario
The following provides a description of the information presented by type of output tables in
Exhibit 9 and the implication for the Design Base scenario.
Exhibit 9 provides a snapshot by year of whether a specific lateral to an AOI needs an expansion
and whether that expansion is a preferred one as opposed to a fill or an alternative lateral
resource. Figure 56 shows the first year of the Upstream Transportation and Lateral Summary,
for the Design Base scenario.
The "Total Peak Day" is the peak day that includes RS, GS, LV-1, and T-4 customers, since the
distribution system must maintain reliability for these customers. The"Existing Capacity" column
is the amount of deliverability Intermountain has on the distribution system for each area of
interest. The "% of Existing Capacity" is the percentage of total peak day compared to existing
capacity. The"Existing+ Upgrade Capacity"column is the amount of deliverability Intermountain
has on the distribution system for each area of interest after the upgrades discussed in the
Capacity Enhancements section take place. The "% of Existing + Upgrade Capacity" is the
Page 136

percentage of total peak day compared to the upgraded capacity. The table for the base year
through the final year in the planning horizon displays these conditions for the Design Base
scenario (Exhibit 9).
2025 Base Year(Dth)
%of Existing Planned Capacity Existing+ %of Existing+
Area of Interest Total Peak Day Existing Capacity Capacity Upgrade Upgrade Capacity Upgrade Capacity
IDAHO FALLS 86,121 90,400 95% 18,900 109,300 79%
SUN VALLEY 19,994 1 20,000 100% 4,750 24,750 81%
CANYON COUNTY 101,399 103,200 98% 35,800 139,000 73%
STATE STREET 75,346 82,000 92% 82,000 92%
CENTRALADA 72,996 74,500 98% 12,500 87,000 84%
ALL OTHER 276,942
Figure 56:Lateral Summary by Year
Figure 57 shows the Annual Traditional Supply Resources Results from Exhibit 8 for the Design
Base scenario for the major supply areas. DSM is also provided in Exhibit 8 in a separate table.
Supply Name Property Units 2025 2026 2027 2028 2029 2030
AECO Base Take Quantity BBtu 12,867 12,907 12,949 13,042 13,058 13,112
AECO Base Price $/MMBtu $ 1.81 $ 2.39 $ 2.52 $ 2.47 $ 2.48 $ 2.56
AECO Base Commodity Cost $0 $ 23,350.45 $ 30,811.28 $ 32,642.64 $32,275.08 $32,406.32 $33,512.88
AECO Base W Take Quantity BBtu 18,250 18,575 18,851 19,226 19,416 19,718
AECO Base W Price $/MMBtu $ 1.91 $ 2.49 $ 2.62 $ 2.57 $ 2.58 $ 2.66
AECO Base W Commodity Cost $0 $ 39,425.40 $ 47,823.07 $ 54,778.30 $53,538.87 $53,303.12 $54,730.14
Figure 57:Annual Traditional Supply Resources Results
The supply resources in the detailed output tables have the following output parameters:
• Total Commodity Cost by year
• Monthly Supply by basin and type of Supply
• Unit Commodity Cost
The total commodity cost is the total dollar amount spent on gas purchased at the supply group
location on an annual basis. The monthly supply is the amount of gas purchased at the supply
group. The unit commodity cost is the dollar per dekatherm that was spent on purchasing the
gas at each supply location. Exhibit 8 also includes the daily purchase amount by supply location
for design day.
Page 137

A sample of the Annual Transportation Resources Results from Exhibit 8 for the Design Base
scenario is displayed Figure 58. Exhibit 8 also provides transportation results by month for the
planning horizon.
Transport Name Property Units 2025 2026 2027 2028 2029 2030 2031
FTHLS 1 Flow Out BBtu 1,571 1,541 1,330 1,344 1,456 1,023 866
FTHLS 1 Fixed Costs $0 $ 236.07 $ 236.07 $ 236.07 $ 236.72 $ 236.07 $ 236.07 $ 236.07
FTHLS 1 Total Variable Cost! $0 $ - $ - $ - $ - $ - $ - $ -
FTHLS 2 Flow Out BBtu 19,198 19,256 18,772 18,902 16,779 23,095 19,630
FTHLS 2 Fixed Costs $0 $ 2,913.81 $ 2,913.81 $ 2,913.81 $ 2,921.79 $ 2,913.81 $ 2,913.81 $ 2,913.81
FTHLS 2 Total Variable Cost! $0 $ - $ - $ - $ - $ - $ - $ -
FTHLS 3 Flow Out BBtu 2,604 2,706 2,558 2,349 2,326 2,482 2,280
FTHLS 3 Fixed Costs $0 $ 288.03 $ 288.03 $ 288.03 $ 289.94 $ 288.03 $ 288.03 $ 288.03
FTHLS 3 Total Variable Cost! $0 $ - $ - $ - $ - $ - $ - $ -
FTHLS 4 Flow Out BBtu 1,691 1,723 1,447 1,377 1,501 1,421 1,356
FTHL54 Fixed Costs $0 $ 245.44 $ 245.44 $ 245.44 $ 246.11 $ 245.44 $ 245.44 $ 245.44
FTHLS 4 Total Variable Cost! $0 $ - $ - $ - $ - $ - $ - $ -
Figure 58:Annual Transportation Resources Results
The transportation resources in the detailed output tables have the following output parameters:
• D1 Cost
• Outflow
• Transportation Cost
The D1 cost is the total dollars spent on the transportation contracts based on the pipelines. The
outflow is the actual amount of gas that flowed on the associated transport group and the
transportation costs are the total dollars spent on the transportation rate. Exhibit 8 also includes
the outflow on design day.
Other Scenarios
Upstream Transportation and Lateral Summary tables for the high and low customer growth as
well as normal weather are provided in Exhibit 10. One notable result from the other scenarios
is that even under the most extreme scenario, design weather with high growth, there is still
sufficient upstream transportation and distribution system capacity to serve customers through
the planning horizon when including the planned solutions for shortfalls in the Planning Results
chapter.
4.5.12 Summary
In summary, the optimization model employs utility standard practice method to optimize
Intermountain's system via linear programming through PLEXOS°. The optimization includes
DSM as a decrement to demand and also optimizes storage injections and withdrawals across
Page 138

seasons. An analysis on lateral expansion is performed as well as an analysis to check for any
shortfalls in upstream transportation or supply capacity.
Page 139

4.6 Planning Results
4.6.1 Overview
Throughout previous sections of the IRP, robust analysis has been performed to determine how
the Company will provide safe, reliable, and least cost gas to customers. This section discusses
the planning results from distribution system planning after capacity enhancements are applied.
After discussing the enhancement solutions for the forecasted capacity deficits, this section will
also compare the peak delivery deficits of the total company as well as each AOI during the three
common years of the 2025 and 2023 IRP filings. The 2025 IRP is unique compared to previous
IRPs, as the 2025 IRP includes a lot of capital investments that have been recently or soon to be
completed projects, which have increased the Company's capacity at each AOI. Finally, the
planning results for upstream transportation shortfalls are discussed.
4.6.2 Distribution System Planning
Canyon County
In the Capacity Enhancements section, Intermountain mentions that Canyon County has seen
significant capital investments at the AOI that provides enough capacity over anticipated growth
to 2030.
The following graph (Figure 59) shows no deficit in the final year of the planning horizon under
the base case scenario with the completion of the proposed capacity upgrades.
Page 140

2030 Load Demand Curve
Design Base Case
Canyon County Lateral
160,000
140,000 — — — — — .
120,000 Peak Day 119,200 Dth's
100,000
0 80,000
60,000
40,000
20,000
0 O 0� 4, C� O'�O 0,60 OHO OHO OHO 0,60 OHO 0,60 (SIP1o\ti�ti yy\ti�ti titi�y\� y\ti�ti �\ti�ti �\ti�ti �\ti�ti h\ti�ti �\ti�ti �\ti�ti �\ti�ti C)
Demand less DSM — — Maximum Physical Deliverability 103,200 Deliverability after Reinforcement 139,000
L
Figure 59:LDC Design Base Case—Canyon County
Page 141

Central Ada County
In the Capacity Enhancements section, Intermountain mentions that Central Ada has seen
significant capital investments at the AOI that provides enough capacity over anticipated growth
to 2030.
The following graph (Figure 60) shows no deficit in the final year of the planning horizon under
the base case scenario after completion of the proposed capacity upgrade.
2030 Load Demand Curve
Design Base Case
Central Ada Lateral
100,000
90,000
80,000 ♦-
70,000
60,000
0 50,000
40,000
30,000
20,000
10,000
050 030 060 OHO 050 050 OHO
ti 050 OHO
yo\ti�ti yy\ti�ti titi�y\� y\ti�ti �\ti�ti �\ti�ti �\ti�ti �\ti�ti �\ti�ti 1\ti� 00
Demand less DSM — — Maximum Physical Deliverability — — Deliverability after Reinforcement 87,000
Figure 60:LDC Design Base Case—Central Ada
Page142

Sun Valley Lateral
In the Capacity Enhancements section, Intermountain mentions that Sun Valley has seen
significant capital investments at the AOI that provides enough capacity over anticipated growth
to 2030.
The following graph (Figure 61) shows no deficit in the final year of the planning horizon under
the base case scenario after completion of the proposed capacity upgrade.
2030 Load Demand Curve
Design Base Case
Sun Valley Lateral
30,000
25,000
awneak nz y 21,240 n+h ls
20,000
0 15,000
10,000
5,000 —
tio�ti��oy� y � tie ti�ti��o�o ti�ti\�o�o 3�ti��o�o 0)\y\�o3o
Demand less DSM Maximum Physical Deliverability 20,000 — Deliverability after Reinforcement 24,750
Figure 61:LDC Design Base Case—Sun Valley Lateral
Page 143

Idaho Falls Lateral
In the Capacity Enhancements section, two options are discussed to meet 2026 capacity needs,
the Wapello compressor station or a Phase VI 16-inch pipeline with an additional LNG Tank in
Rexburg. The option chosen was the Wapello compressor station. An additional upgrade is
needed to meet 2030 capacity needs, in which two options were discussed; a separate
compressor station or a pipeline loop. Intermountain is considering the pipeline loop as it is the
lowest cost option.
The following graph shows no deficit in the final year of the planning horizon under the base case
scenario after completion of the proposed capacity upgrade.
2030 Load Demand Curve
Design Base Case
Idaho Falls Lateral
140,000
120,000
Peak Day 99,930 Dth's
100,000 - - - - -
80,000
s
0
60,000
40,000
20,000
6 OP
yo\ti�ti titi�y\� titi�y\� y\ti�ti �\ti�ti �\ti�ti p\ti�ti �\ti�ti �\ti�ti �\ti�ti �\ti�ti �\ti�ti
Demand less DSM — — Deliverability after Reinforcement — — Maximum Physical Deliverability with LNG Storage
Figure 62:LDC Design Base Case—Idaho Falls Lateral
Page144

N. of State Street Lateral
In the Capacity Enhancements section, two options are discussed to determine the best way to
solve capacity shortfalls for the State Street Lateral.The option chosen was the State Street Phase
II Uprate.
The following graph shows no deficit in the final year of the planning horizon under the base case
scenario after completion of the proposed capacity upgrade.
2030 Load Demand Curve
Design Base Case
State Street Lateral
100,000
90,000 Peak Day 86,790 Dth's
n
80,000 — — — — — — — — — — — — — — — — —
70,000 —
60,000
0 50,000
40,000
30,000
20,000
10,000
yo\ti�ti yy\ti�ti titi�y\� y\ti�ti �\1�ti �\1�ti p\1�ti y\ti�ti �\1�ti ^\ti�ti �\ti�ti �\ti�ti
Demand less DSM — — Maximum Physical Deliverability82,000 — — Deliverability after Reinforcements 95,000
Figure 63:LDC Design Base Case—N. of State Street Lateral
Page145

2023 IRP vs. 2025 IRP Common Year Comparisons
This section compares any firm delivery deficits prior to any completed projects after the filing of
the IRP for each AOI and the Total Company during the three common years of the 2025 and 2023
IRP filings.
Canyon County Area Delivery Deficit Comparison
2025 IRP FIRM DELIVERY DEFICIT—CANYON COUNTY
2025 2026 2027
Peak Day Deficit 0 0 0
Total Winter Deficit' 0 0 0
Days Requiring Additional Resources 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
Table 50: 2025 IRP Canyon County Design Weather Delivery Deficit
2023 IRP FIRM DELIVERY DEFICIT—CANYON COUNTY
2025 2026 2027
Peak Day Deficit 0 0 0
Total Winter Deficit' 0 0 0
Days Requiring Additional Resources 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
Table 51: 2023 IRP Canyon County Design Weather Delivery Deficit
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2025 IRP FIRM DELIVERY DEFICIT—CANYON COUNTY
• . 1
2025 2026 2027
Peak Day Deficit 0 0 0
Total Winter Deficit' 0 0 0
Days Requiring Additional Resources 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
Table 52: 2023 IRP vs. 2025 IRP Canyon County Design Weather Delivery Deficit
Central Ada County Firm Delivery Deficit Comparison
2025 IRP FIRM DELIVERY DEFICIT—CENTRAL ADA DESIGN BASE CASE(Dth)
2025 2026 2027
Peak Day Deficit 0 0 0
Total Winter Deficit' 0 0 0
Days Requiring Additional Resources 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
Table 53: 2025 IRP Central Ada Design Weather Delivery Deficit
1 .D. DESIGN BASE CASE (Dth)
2025 2026 2027
Peak Day Deficit 0 0 0
Total Winter Deficit' 0 0 0
Days Requiring Additional Resources 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
Table 54: 2023 IRP Central Ada Design Weather Delivery Deficit
Page147

2025 IRP FIRM DELIVERY DEFICIT—CENTRAL . . DESIGN BASE CASE
1
2025 2026 2027
Peak Day Deficit 0 0 0
Total Winter Deficit' 0 0 0
Days Requiring Additional Resources 0 0 0
lEqual to the total winter sendout in excess of distribution capacity.
Table 55: 2023 IRP vs. 2025 IRP Central Ada Design Weather Delivery Deficit
Sun Valley Lateral Delivery Deficit Comparison
2025 IRP FIRM DELIVERY DEFICIT—SUN VALLEY LATERAL DESIGN BASE CASE (Dth)
2025 2026 2027
Peak Day Deficit 0 0 0
Total Winter Deficit' 0 0 0
Days Requiring Additional Resources 0 0 0
lEqual to the total winter sendout in excess of distribution capacity.
Table 56: 2025 IRP Sun Valley Lateral Design Weather Delivery Deficit
2023 IRP FIRM DELIVERY DEFICIT—SUN VALLEY LATERAL DESIGN BASE CASE (Dth)
2025 2026 2027
Peak Day Deficit 0 0 0
Total Winter Deficit' 0 0 0
Days Requiring Additional Resources 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
Table 57: 2023 IRP Sun Valley Lateral Design Weather Delivery Deficit
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2025 IRP FIRM DELIVERY DEFICIT—SUN VALLEY LATERAL DESIGN BASE CASE
• 1
2025 2026 2027
Peak Day Deficit 0 0 0
Total Winter Deficit' 0 0 0 I
Days Requiring Additional Resources 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
Table 58: 2023 IRP vs. 2025 IRP Sun Valley Lateral Design Weather Delivery Deficit
Idaho Falls Lateral Peak Delivery Deficit Comparison
1 DA • 1
2025 2026 2027
(Peak Day Deficit 0 0 0
Total Winter Deficit' 0 0 0
Days Requiring Additional Resources 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
Table 59: 2025 IRP Idaho Falls Lateral Design Weather Delivery Deficit
1 DA • FALLS LATERAL DESIGN BASE CASE (Dth)
2025 2026 2027 I
Peak Day Deficit 0 0 0
Total Winter Deficit' 0 0 0 I
Days Requiring Additional Resources 0 0 0 I
'Equal to the total winter sendout in excess of distribution capacity.
Table 60: 2023 IRP Idaho Falls Lateral Design Weather Delivery Deficit
Page149

2025 IRP FIRM DELIVERY DEFICIT-IDAHO FALLS LATERAL DESIGN BASE CASE
• • 1
2025 2026 2027
Peak Day Deficit 0 0 0
Total Winter Deficit' 0 0 0
Days Requiring Additional Resources 0 0 0
lEqual to the total winter sendout in excess of distribution capacity.
Table 61: 2023 IRP vs. 2025 IRP Idaho Falls Lateral Design Weather Delivery Deficit
N. of State Street Lateral Firm Delivery Deficit Comparison
2025 IRP FIRM DELIVERY DEFICIT-N.of STATE STREET LATERAL DESIGN BASE CASE(Dth)
2025 2026 2027
Peak Day Deficit 0 0 0
Total Winter Deficit' 0 0 0
Days Requiring Additional Resources 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
Table 62: 2025 IRP N. of State Street Lateral Design Weather Delivery Deficit
2023 1 RIP FIRM DELIVERY DEFICIT—N. of STATE STREET LATERAL DESIGN BASE CASE (Dth)
2025 2026 2027
Peak Day Deficit 0 0 0
Total Winter Deficit' 0 0 0
Days Requiring Additional Resources 0 0 0
lEqual to the total winter sendout in excess of distribution capacity.
Table 63: 2023 IRP N. of State Street Lateral Design Weather Delivery Deficit
Page150

2025 IRP" of BASE CASE
• • 1
2025 2026 2027
Peak Day Deficit 0 0 0
Total Winter Deficit' 0 0 0
Days Requiring Additional Resources 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
Table 64: 2023 IRP vs. 2025 IRP N. of State Street Lateral Design Weather Delivery Deficit
Total Company Peak Delivery Deficit Comparison
125 IRP FIRM DELIVERY DEFICIT—TOTAL COMPANY
2025 2026 2027
Peak Day Deficit 0 2,258 11,194
Total Winter Deficit' 0 2,258 11,194
Days Requiring Additional Resources 0 1 1
'Equal to the total winter sendout in excess of interstate capacity less total"peaking"storage.Peaking storage does not require the use of
Intermountain's traditional interstate capacity to deliver inventory to the citygate.
Table 65: 2025 IRP Total Company Design Weather Delivery Deficit
2023 IRP FIRM DELIVERY DEFICIT—TOTAL COMPANY
2025 2026 2027
Peak Day Deficit 0 0 0
Total Winter Deficit' 0 0 0
Days Requiring Additional Resources 0 0 0
'Equal to the total winter sendout in excess of interstate capacity less total"peaking"storage.Peaking storage does not require the use of
Intermountain's traditional interstate capacity to deliver inventory to the citygate.
Table 66: 2023 IRP Total Company Design Weather Delivery Deficit
Page151

2025 IRP" FIRM DELIVERY DEFICIT—TOTAL COMPANY
• 1
2025 2026 2027
Peak Day Deficit 0 2,258 11,194
Total Winter Deficit' 0 2,258 11,194
Days Requiring Additional Resources 0 1 1
'Equal to the total winter sendout in excess of interstate capacity less total"peaking"storage.Peaking storage does not require the use of
Intermountain's traditional interstate capacity to deliver inventory to the citygate.
Table 67: 2023 IRP vs. 2025 IRP Total Company Design Weather Delivery Deficit
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4.6.3 Upstream Modeling
Upstream Modeling Results
The upstream modeling results look at the upstream resources to ensure there is sufficient supply,
storage, and transportation of gas to Intermountain's distribution system. As mentioned in the
Traditional Supply Resources section, supply remains plentiful at the supply basins for the
foreseeable future. As Intermountain continues to experience extreme growth, the Company's
design capacity begins to hit a shortfall in the planning horizon. Due to this growth, Intermountain
shows a shortfall in 2026 and grows throughout the final year of the planning horizon. The
following graph (Figure 64) shows the shortfall created by expiring contracts.
2026 Load Demand Curve
Design Base Case
Total Company
600,000
Peak Day 534,905 Dth
500,000 —
400,000
0 300,000
200,000
100,000
10/1/2025 11/1/2025 12/1/2025 1/1/2026 2/1/2026 3/1/2026 4/1/2026 5/1/2026 6/1/2026 7/1/2026 8/1/2026 9/1/2026
—Core+W-1 Demand less DSM — —Maximum Transport Deliverability
Figure 64: 2026 Design Base Case—Total Company
Solving Upstream Resources Shortfall
The options to solve the transportation shortfall that the Company anticipates happening during
the planning horizon are incremental transportation and satellite LNG. As outlined during the
IGRAC 4 presentation, Intermountain's most realistic options are the Rockies Connector project
and satellite LNG.
The Rockies Connector project is a project put forth by Northwest Pipeline to increase the capacity
from the Rockies area flowing north to Stanfield and Sumas. Satellite LNG would consist of adding
an additional LNG facility to the Company's distribution system.
Intermountain ultimately selected the Rockies expansion because it provides a strategic balance
of reliability and cost efficiency in a shifting energy landscape.The company recognized significant
Page 153

uncertainty surrounding the timing and feasibility of future capacity expansion projects, making it
critical to secure near-term solutions. At the same time, LNG project costs are prohibitively high,
as outlined in Table 68, limiting their attractiveness as a competitive option. By pursuing the
Rockies expansion, Intermountain gains valuable basin diversity between AECO and the Rockies,
strengthening supply flexibility and reducing exposure to single-market risks while positioning
itself to adapt to evolving infrastructure developments.
CapacityFacility Planning Filing Project
Link Cost
—$489
Puget Sound Tacoma WA UTC million —9.6 million
LNG
Energy PSE Gas IRP docket capital cost
(WA), UG-230393 (end of dth
2022)
Pacific Lelu Island Planned
NorthWest NA BC EAO, $1 1.4-18 —18-20M Dth
LNG (BC, LNG Export (Petronas) CEAA 2012 billion annually
z
canceled) Project investment
NW OPUC Capacity in
Natural Peak-shaving NW docket UG undisclosed PHMSA/permit
(OR/WA)3 LNG NaturallRP 456 filings
FortisBC Tilbury BCUC BCUC —$1.14 —25.4 million
(BC)4 LNG Tilbury Order billion dth
LNG CPCN G-62-23
Table 68: Regional LNG Projects
It is important to remember that the resource optimization model provides information and does
not decide the ultimate solution. The resource optimization model results will be provided to
Intermountain's Gas Supply Oversight Committee (GSOC. GSOC will need to consider a longer
time frame when looking at upstream transportation since those contracts typically are only
available for purchase in long-term blocks.Therefore, it may make more sense to do a full renewal.
Ultimately, GSOC will make a final decision on the solution to meet the forecasted transportation
shortfall.
1 See:december12023.pdf, PSE LNG FEIS Cover Pages.pdf
z See: Pacific North West LNG Project, British Columbia-Offshore Technolopv
'See: Ic79has155146.pdf
'See: BCUC Approves FortisBC's Tilbury Liquefied Natural Gas
Page 154

4.6.4 Conclusion
The distribution system planning results showed that the Company has and continues to need to
address capacity shortfalls at each of the Area of Interests. The Capacity Enhancements section
describes each solution and the updated capacity values are shown in this section to provide
sufficient capacity over the planning horizon. The upstream modeling showed a shortfall due to
design day growth. That shortfall will be solved by incremental transportation, with the ultimate
decision coming from Intermountain's GSOC.
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4.7 Infrastructure Replacement
4.7.1 Overview
Intermountain Gas Company is committed to providing safe and reliable natural gas service to its
customers. As part of this commitment, Intermountain proactively monitors its pipeline system
utilizing risk management tools and engineering analysis. Additionally, the Company adheres to
federal, state and local requirements to replace or improve pipelines and infrastructure as
required. Infrastructure that is identified as a potential risk is reviewed and prioritized for
replacement or risk mitigation.
During the IRP planning period, Intermountain will address five significant infrastructure
replacement projects. These replacement projects are not growth driven.
4.7.2 American Falls Neely Bridge Snake River Crossing
The Neely bridge crossing is a six-inch steel high pressure pipeline above ground crossing over
the Snake River where the pipe is hanging on a bridge and is scheduled for replacement in 2026.
The pipe has been identified for replacement since it is a suspended crossing installed in 1961
which is difficult to inspect and maintain coating on and has had issues with expansion and
contraction of the bridge which has resulted in damage to the facilities.
To address these issues Intermountain is recommending that this above ground crossing be
replaced with a below ground crossing under the Snake River using horizontal directional
drilling.
4.7.3 Rexburg Snake River Crossing
The Rexburg Snake River crossing is an eight-inch steel transmission pipeline installed under the
Snake River southwest of Rexburg which has been identified as an infrastructure replacement
project, tentatively scheduled for 2028 design and permitting and 2029 construction. The
pipeline was identified for replacement due to risks related to the Snake River and surrounding
flood plain. The location of the pipeline under the Snake River and perpendicular to the river
along its east bank leave the pipeline susceptible to loss of adequate cover should the river's rate
of flow increase to the point of spilling over the existing bank and/or scouring the existing river
bottom.
The Rexburg Snake River crossing has been monitored and has required occasional attention.
The riverbank has been rebuilt and reinforced by Intermountain to prevent undermining of the
bank and reduce the potential to flood, and the Company has installed engineered scour
protection measures over the top of the pipeline to prevent cover loss within the river. These
efforts have been successful to date. However, due to the ongoing monitoring and mitigation
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efforts, along with the ever-present risks associated with this scenario, the Company plans to
replace the existing pipeline.
Intermountain's selected replacement method for this existing river crossing is to utilize
horizontal directional drilling technology to install a new pipeline much further below the river
bottom and surrounding flood area. Horizontal directional drilling will allow the pipeline to be
installed much deeper in the ground than conventional installation practices and will avoid any
disturbance to the Snake River and the sensitive land surrounding the river. The significant
increase in pipeline depth will mitigate the existing risk.
4.7.4 Shoshone Sun Valley Transmission Line Replacement
The Shoshone area is known for rocks due to lava formations. The Sun Valley transmission line
has been identified at shallow depth in a field that is farmed and tilled creating a abnormal
operating condition, and safety concern and potential excavation risk to the pipeline. 2800 feet
of 8-inch transmission line needs to be replaced to get the line back to having acceptable cover.
This project is planned for 2026 design and 207 construction.
4.7.5 System Safety and Integrity Program (SSIP)
The System Safety and Integrity Program ("SSIP") is a structured pipe replacement program for
replacing early vintage plastic pipe and early vintage steel pipe.
Early vintage plastic pipe includes plastic mains, service lines, and associated fittings installed
earlier than January 1, 1995. Early vintage plastic pipe is further divided into Pre-1983 and Post-
1982. Pre-1983 includes pipe installed prior to January 1, 1983 that may be susceptible to
possible low ductile inner wall characteristics that can result in slow crack growth and slit
failures, as documented by the Pipeline and Hazardous Materials Safety Administration
("PHMSA"), PHMSA-2004-19856.1 Post-1982 includes pipe installed between January 1, 1983
and December 31, 1994 and are classified as early vintage plastic pipe to account for different
inventory levels and rates of new material adoption throughout Intermountain's operating
locations.
Early vintage steel pipe includes steel mains, service lines, and associated fittings installed
earlier than January 1, 1970. This pipe presents an increased risk of failure due to external
corrosion, material failure, weld or joint failure, and equipment failure.
Intermountain's SSIP utilizes its Distribution Integrity Management Program (DIMP) Risk Model
to calculate relative risk scores for Intermountain's distribution system. The DIMP risk model
sums up the assigned likelihood scores for each threat and consequence factors for each
'See:https://www.federalre,gig ster.gov/documents/2007/09/06/07-4309/pipeline-safety-updated-notification-of-the-
susceptibility-to-premature-brittle-like-cracking-o f.
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segment of Intermountain's distribution system. The total likelihood factor is then multiplied
by the total consequence factor to establish a total relative risk score. The relative risk score is
then used to establish a weighted average risk (WAR) score for each town within Idaho. The
WAR score is then used to identify towns with increased risk related to early vintage plastic pipe
and early vintage steel pipe. Ongoing analysis of early vintage plastic pipe and early vintage
steel pipe continues to show that this pipe has a greater likelihood to leak and/or have
substandard pipe conditions (corrosion, welds/joints, materials, equipment). These segments
of main and service lines have an elevated risk of failure as validated by DIMP risk analysis and
are, therefore, prioritized for replacement. Pipeline replacement is typically the most viable
option to remediate risks associated with corrosion, material failure, weld/joint failure,
equipment failure, and missing data threats. The SSIP program addresses safety, reliability, and
operational risks by replacing pipe systematically, where Intermountain has determined that
replacement is an appropriate action to reduce risk.
Since 2013, Intermountain has been actively replacing segments of early vintage plastic pipe
and early vintage steel pipe within its distribution system.
Intermountain completed SSIP pipe replacement in Boise, Idaho in 2025. The Boise SSIP pipe
replacement project is a multi-year project primarily focusing on the replacement of Pre-1983
early vintage plastic main and service lines with MDPE pipe. Boise was identified in 2023 as
Intermountain's 2nd highest risk town with early vintage steel pipe and early vintage plastic pipe
in the state of Idaho, by Intermountain's SSIP. The Boise SSIP pipe replacement project started
in 2023 and will continue through 2027.
Intermountain currently has approximately $4.30 (2026) — $4.95 (2030) million budgeted for
SSIP replacement annually, which is used for replacing high risk early vintage plastic pipe and
early vintage steel pipe. The SSIP replacement plan will continue through the duration of the
IRP.
4.7.6 Transmission Re-Confirmation
PHMSA issued RIN 1 of the Final Rule of Docket No. PHMSA-2011-0023 — Safety of Gas
Transmission and Gathering Pipelines: MAOP Reconfirmation, Expansion of Assessment
Requirements, and Other Related Amendments on October 1, 2019. This final rule addressed
congressional mandates, National Transportation Safety Board recommendations, and
responds to public input. The amendments in this final rule address integrity management
requirements and other requirements, and they focus on the actions that must be taken to
reconfirm the maximum allowable operating pressure (MAOP) of previously untested
transmission pipelines and pipelines lacking certain material or operational records,the periodic
assessment of pipelines in populated areas not designated as "high consequence areas," the
reporting of exceedances of maximum allowable operating pressure, the consideration of
seismicity as a risk factor in integrity management, safety features on in-line inspection
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launchers and receivers, a 6-month grace period for 7-calendar-year integrity management
reassessment intervals, and related recordkeeping provisions.
MAOP reconfirmation requires Intermountain to reconfirm the MAOP of transmission pipeline
segments where the records needed to substantiate the MAOP are not traceable, verifiable,
and complete (TVC). Records to confirm MAOP include pressure test records or material
property records (mechanical properties) that verify the MAOP is appropriate for the class
location. Pipeline segments with missing records can be reconfirmed using one of six methods
which include:
1. Pressure Test
2. Pressure Reduction
3. Engineering Critical Assessment
4. Pipe Replacement
5. Pressure Reduction for Pipeline Segments with Small Potential Impact Radius
6. Alternative Technology
Intermountain currently doesn't have anything budgeted for MAOP reconfirmation pipe
replacement. As work continues to reconfirm MAOP, transmission pipeline segments may be
identified for replacement where the records needed to substantiate the MAOP are not TVC.
MAOP reconfirmation activities will continue through the duration of the IRP.
4.7.7 Shorted Casing Replacement or Abandonment Program (SCRAP)
The Shorted Casing Replacement/Abandonment Program (SCRAP) identifies and replaces
shorted casings. A steel carrier pipe installed inside a steel casing is required to be electrically
isolated from the steel casing. To determine if a steel carrier is electrically isolated from a steel
casing, each casing is tested annually, per Company procedure, to determine if the casing is
shorted or electrically isolated. If a casing is determined to be shorted, it must be mitigated or
replaced before its status can be resolved as not shorted. Mitigation methods are a short-term
remedial action as the metal-to-metal contact may reoccur. Therefore, shorted casing
replacement or shorted casing abandonment/removal are the preferred methods to minimize
the threat of a shorted casing. Eliminating shorted casings reduces ongoing 0&M maintenance
costs associated with shorted casings.
Intermountain currently has approximately $494,000 — $701,000 budgeted, for 2026 through
2030, for SCRAP replacement annually, which is used for the replacement of shorted casings.
SCRAP will continue through the duration of the IRP.
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5. Glossary
Agent (Marketer)
A legal representative of buyers, sellers or shippers of natural gas in negotiation or operations of
contractual agreements.
All Other Customers Segment (All Other)
All other segments of the Company's distribution system serving core market customers in Ada
County not included in the State Street Lateral or Central Ada County, as well as customers in
Bannock, Bear Lake, Caribou, Cassia, Elmore, Gem, Gooding, Jerome, Minidoka, Owyhee,
Payette, Power, Twin Falls, and Washington counties; an Area of Interest for Intermountain.
Area of Interest (AOI)
Distinct segments within Intermountain's current distribution system.
British Thermal Unit (BTU)
The amount of heat that is necessary to raise the temperature of one pound of water by 1 degree
Fahrenheit
Bundled Service
Gas sales service and transportation service packaged together in a single transaction in which
the utility, on behalf of the customer, buys gas from producers and then transports and delivers
it to the customer.
Canyon County Area (CCA)
A distinct segment of Intermountain's distribution system which serves core market customers
in Canyon County; an Area of Interest for Intermountain.
Central Ada County (CAC)
Multiple high-pressure pipeline systems which serve core market customers in Ada County
between Chinden Boulevard and Victory Road, north to south, and between Maple Grove Road
and Black Cat Road, east to west; an Area of Interest for Intermountain.
Citygate
The points of delivery between the interstate pipelines providing service to the utility or the
location(s) at which custody of gas passes from the pipeline to the utility.
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Commercial
A customer that is neither a residential nor a contract/large volume customer whose
requirements for natural gas service do not exceed 2,000 therms per day. These customers are
typically commercial businesses or small manufacturing facilities.
Contract Demand (CD)
The maximum peak day amount of distribution capacity that Intermountain guarantees to
reserve for a firm customer each day. The amount is specified in the customer contract. Also see
MDFQ.
Core Market
All residential and commercial customers of Intermountain Gas Company. Includes all customers
receiving service under the RS and GS tariffs.
Customer Management Module (CMM)
A software product, provided by DNV as part of their Synergi Gas product line, to analyze natural
gas usage data and predict usage patterns on an individual customer level.
Delivery (Receipt Point)
Designated points where natural gas is transferred from one party to another. Receipt points are
those locations where a local distribution company delivers, and an interstate pipeline receives,
gas supplies for re-delivery to the local distribution company's city gates.
Design Year
An estimate of the highest level of annual customer demand that may occur, incorporating
extreme cold or peak weather events; a measure used for planning capacity requirements.
Design Weather
Heating degree days that represent the coldest temperatures that may occur in the IGC service
territory.
Direct Use
The use of natural gas at the point of final heating energy use, such as natural gas space heating,
water heating, cooking, and other heating uses, as opposed to burning natural gas in a power
plant to generate electricity to be used at the point(s) of use to for site space heat, water heat,
cooking heat and other heat applications. Direct use is a much more efficient use of natural gas.
Demand Side Management (DSM)
Programs implemented by the Company and utilized by its customers to influence the amount
and timing of natural gas consumption.
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Electronic Bulletin Board (EBB)
A generic name for the system of electronic posting of pipeline transmission information as
mandated by FERC.
FERC - Federal Energy Regulatory Commission
The federal agency that regulates interstate gas pipelines and interstate gas sales under the
Natural Gas Act. Successor to the Federal Power Commission, the FERC is considered an
independent regulatory agency responsible primarily to Congress, but it is housed in the
Department of Energy.
Firm Customer
A customer receiving service under rate schedules or contracts designed to provide the
customer's gas supply and distribution needs on a continuous basis, even on a peak day.
Firm Service
A service offered to customers under schedules or contracts which anticipate no interruptions.
Fixed Physical
A fixed forward (also known as a fixed price physical contract) is an agreement between two
parties to buy or sell a specified amount of natural gas at a certain future time, at a specific price,
which is agreed upon at the time the deal is executed. It operates much like the price swap
without the margin call risk.
Formation
A formation refers to either a certain layer of the earth's crust, or a certain area of a layer. It often
refers to the area of rock where a petroleum or other hydrocarbon reservoir is located. Other
related terms are basin or play.
Gas Transmission Northwest (GTN)
A U.S. pipeline which begins at the U.S.-Canadian border near Kingsgate, British Columbia and
interconnects with Williams Northwest Pipeline at the Stanfield receipt point in Oregon.
Heating Degree Day (HDD)
An industry-wide standard, measuring how cold the weather is based on the extent to which the
daily mean temperature falls below a reference temperature base, which for IGC, is 65 degrees
Fahrenheit.
Idaho Falls Lateral (IFL)
A distinct segment of Intermountain's distribution system which serves core market customers
in Bingham, Bonneville, Fremont, Jefferson, and Madison counties; an Area of Interest for
Intermountain.
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Industrial Customer
For purposes of categorizing large volume customers, any customer utilizing natural gas for
vegetable, feedstock or chemical production, equipment fabrication and/or manufacturing or
heating load for production purposes.
Institutional Customer
For purposes of categorizing large volume customers, this would include business such as
hospitals, schools, and other weather sensitive customers.
Interruptible Customer
A customer receiving service under rate schedules or contracts which permit interruption of
service on short notice due to insufficient gas supply or capacity.
Interruptible Service
Lower-priority service offered to customers under schedules or contracts which anticipate and
permit interruption on short notice, generally in peak-load seasons, by reason of the higher
priority claim of firm service customers and other higher priority users. Service is available at any
time of the year if distribution capacity and/or pressure is sufficient.
Large Volume Customer
Any customer receiving service under one of the Company's large volume tariffs including LV-1,
T-3, and T-4. Such service requires the customer to sign a minimum one-year contract and use at
least 200,000 therms per contract year.
Liquefied Natural Gas (LNG)
Natural gas which has been liquefied by reducing its temperature to minus 260 degrees
Fahrenheit at atmospheric pressure. In volume, it occupies one-six-hundredth of that of the
vapor at standard conditions.
Load Demand Curve (LDC)
A forecast of daily gas demand using design or normal temperatures, and predetermined usage
per customer.
Local Distribution Company
A retail gas distribution company, utility, that delivers retail natural gas to end users.
Lost and Unaccounted for Natural Gas (LAUF)
The difference between volumes of natural gas delivered to Intermountain's distribution system
and volumes of natural gas billed to Intermountain's customers.
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Maximum Daily Firm Quantity (MDFQ)
The contractual amount that Intermountain guarantees to deliverto the customer each day.Also
see Contract Demand.
Methane
Methane is commonly known as natural gas(or CH4) and is the most common of the hydrocarbon
gases. It is colorless and naturally odorless and burns efficiently without many by products.
Natural gas only has an odor when it enters a customer's home because the local distributor adds
it as a safety measure.
Normal Weather
Normal weather is comprised of HDD's that represent the average mean temperature for each
day of the year. Intermountain's Normal Weather is a 30-year rolling average of NOAA's daily
mean temperature.
Northwest Pipeline (Williams Northwest Pipeline, Northwest, NWP)
A 3,900-mile, bi-directional transmission pipeline crossing the states of Washington, Oregon,
Idaho, Wyoming, Utah and Colorado and the only interstate pipeline which interconnects to
Intermountain's distribution system; all gas supply received by the Company is transported by
this pipeline.
NYMEX Futures
New York Mercantile Exchange is the world's largest physical commodity futures exchange.
Futures are financial contracts obligating the buyer to purchase an asset (or the seller to sell an
asset),such as a physical commodity, at a predetermined future date and price. Futures contracts
detail the quality and quantity of the underlying asset; they are standardized to facilitate trading
on a futures exchange. Some futures contracts may call for physical delivery of the asset, while
others are settled in cash.
Peak Shaving
Using sources of energy, such as natural gas from storage, to supplement the normal amounts
delivered to customers during peak-use periods. Using these supplemental sources prevents
pipelines from having to expand their delivery facilities just to accommodate short periods of
extremely high demand.
Peak Day
The coldest day of the design year; a measure used for planning system capacity requirements.
For Intermountain, that day is currently January 15 of the design year.
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PSIG (Pounds per Square Inch Gauge)
Pressure measured with respect to that of the atmosphere. This is a pressure gauge reading in
which the gauge is adjusted to read zero at the surrounding atmospheric pressure. It is commonly
called gauge pressure.
Producer
Natural gas producer is generally involved in exploration, drilling, and refinement of natural gas.
There are independent producers, as well as integrated producers, which are generally larger
companies that produce, transport and distribute natural gas.
Purchased Gas Adjustment or PGA
Intermountain's annual price change to adjust the cost of gas service to its customers, based on
deferrals from the prior year and forward-looking cost forecasts.
Residential Customer
Any customer receiving service under the Company's RS Rate Schedule.
SCADA (Supervisory Control and Data Acquisition)
Remote controlled equipment used by pipelines and utilities to operate their gas systems. These
computerized networks can acquire immediate data concerning flow, pressure or volumes of gas,
as well as control different aspects of gas transmission throughout a pipeline system.
State Street Lateral (SSL)
A distinct segment of Intermountain's distribution system which serves core market customers
in Ada County north of the Boise River, bound on the west by Kingsbury Road west of Star, and
bound on the east by State Highway 21; an Area of Interest for Intermountain.
Sun Valley Lateral (SVL)
A distinct segment of Intermountain's distribution system that serves customers in Blaine and
Lincoln counties; an Area of Interest for Intermountain.
Therm
A unit of heat energy equal to 100,000 British thermal units (BTU). It is approximately the energy
equivalent of burning 100 cubic feet (1 CCF) of natural gas.
Traffic Analysis Zones (TAZ)
An analysis of traffic patterns in certain high traffic areas.
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Transportation Tariff
Tariffs that provide for the redelivery of a shipper's natural gas received into an interstate
pipeline or Intermountain's distribution system. A transportation customer is responsible for
procuring its own supply of natural gas and transporting it on the interstate pipeline system for
delivery to Intermountain at one of its citygate locations.
WCSB (Western Canadian Sedimentary Basin)
A vast natural gas producing region encompassing 1,400,000 square kilometers (540,000 sq mi)
of Western Canada including southwestern Manitoba, southern Saskatchewan, Alberta,
northeastern British Columbia and the southwest corner of the Northwest Territories. It consists
of a massive wedge of sedimentary rock extending from the Rocky Mountains in the west to the
Canadian Shield in the east.
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