20231228 2023 IRP.pdf

December 28, 2023

Ms. Monica Barrios-Sanchez
Interim Commission Secretary
Idaho Public Utilities Commission
P.O. Box 83720
Boise, ID 83720-0074

RE: Case No. INT-G-23-07

Dear Ms. Barrios-Sanchez:

Attached for consideration by this Commission is an electronic submission of Intermountain Gas
Company’s (“Intermountain”) 2023 Integrated Resource Plan (“IRP”).

Intermountain respectfully requests that the Commission acknowledge the 2023 IRP in accordance
with its rules. If you should have any questions regarding the filing, please don’t hesitate to contact
me at [phone] or [e-mail].

Sincerely,

/s/ Lori A. Blattner

Lori A. Blattner
Director, Regulatory Affairs
Intermountain Gas Company

Enclosures

cc: Mark Chiles
Preston Carter  

RECEIVED
2023 DECEMBER 28, 2023 8:58AM
IDAHO PUBLIC
UTILITIES COMMISSION
Intermountain Gas Company
Integrated Resource Plan
2023 – 2028

Integrated Resource Plan 2023 – 2028 ii

Table of Contents
1 Introduction ................................................................................................... 1
1.1 Overview ................................................................................................................................................ 1
1.1.1 About the Company ...................................................................................................................... 1
1.1.2 Customer Base ............................................................................................................................... 2
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 ................................................................................................... 8
1.1.11 Clean Energy Future .................................................................................................................. 9
2 Demand ........................................................................................................ 11
2.1 Demand Forecast Overview ................................................................................................................. 11
2.2 Residential & Commercial Customer Growth Forecast ....................................................................... 12
2.2.1 The Base Case Economic Growth Scenario ................................................................................. 16
2.2.2 Population and Household Growth ............................................................................................. 19
2.2.3 The High and Low Economic Growth Scenarios ........................................................................... 20
2.2.4 Residential Customer Forecast .................................................................................................... 20
2.2.5 Commercial Customer Forecast .................................................................................................. 23
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 .......................................................................................................... 29
2.3.5 Area Specific Degree Days ........................................................................................................... 31
2.4 Large Volume Customer Forecast ........................................................................................................ 31
2.4.1 Introduction ................................................................................................................................. 31
2.4.2 Method of Forecasting ................................................................................................................ 32

Integrated Resource Plan 2023 – 2028 iii

2.4.3 Forecast Scenarios ....................................................................................................................... 33
2.4.4 Contract Demand ........................................................................................................................ 33
2.4.5 “Load Profile” vs MDFQ ............................................................................................................... 34
2.4.6 System Reliability ........................................................................................................................ 34
2.4.7 General Assumptions .................................................................................................................. 35
2.4.8 Base Case Scenario Summary ...................................................................................................... 35
2.4.9 High Growth Forecast Summary ................................................................................................. 36
2.4.10 Low Growth Forecast Summary .............................................................................................. 38
3 Supply and Delivery Resources .................................................................. 40
3.1 Overview .............................................................................................................................................. 40
3.2 Traditional Supply Resources ............................................................................................................... 40
3.2.1 Overview...................................................................................................................................... 40
3.2.2 Background .................................................................................................................................. 41
3.2.3 Gas Supply Resource Options ...................................................................................................... 42
3.2.4 Shale Gas ..................................................................................................................................... 44
3.2.5 Supply Regions ............................................................................................................................ 45
3.2.6 Interstate Pipeline Transportation Capacity ............................................................................... 56
3.2.7 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
3.4.4 Propane ....................................................................................................................................... 65
3.4.5 Satellite/Portable LNG Equipment .............................................................................................. 65
3.4.6 Renewable Natural Gas ............................................................................................................... 66
3.4.7 Hydrogen ..................................................................................................................................... 67
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

Integrated Resource Plan 2023 – 2028 iv

3.5.3 Leak Survey .................................................................................................................................. 69
3.5.4 Damage Prevention and Monitoring ........................................................................................... 70
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 ............................................................................................ 74
3.6.3 Market and Measure Characterization ....................................................................................... 74
3.6.4 Energy Efficiency Potential .......................................................................................................... 76
3.7 Large Volume Energy Efficiency ........................................................................................................... 80
3.8 Avoided Costs ..................................................................................................................................... 83
3.8.1 Overview...................................................................................................................................... 83
3.8.2 Costs Incorporated ...................................................................................................................... 83
3.8.3 Understanding Each Component ................................................................................................ 84
4 Optimization ................................................................................................ 86
4.1 Distribution System Overview.............................................................................................................. 86
4.1.1 System Dynamics ......................................................................................................................... 86
4.1.2 Network Design Fundamentals ................................................................................................... 87
4.2 Modeling Methodology ....................................................................................................................... 88
4.2.1 Model Building Process ............................................................................................................... 88
4.2.2 Usage Per Customer .................................................................................................................... 89
4.2.3 Fixed Network ............................................................................................................................. 90
4.2.4 Model Validation ......................................................................................................................... 90
4.2.5 Distribution System Planning ...................................................................................................... 91
4.2.6 Distribution System Enhancements ............................................................................................ 92
4.2.7 Distribution System Enhancement Considerations ..................................................................... 94
4.2.8 Distribution System Enhancement Selection Guidelines ............................................................ 95
4.2.9 Capital Budget Process ................................................................................................................ 95
4.2.10 Conclusion ............................................................................................................................... 97
4.3 Capacity Enhancements ....................................................................................................................... 98
4.3.1 Overview...................................................................................................................................... 98
4.3.2 Canyon County ............................................................................................................................ 99
4.3.3 State Street Lateral .................................................................................................................... 101

Integrated Resource Plan 2023 – 2028 v

4.3.4 Central Ada County ................................................................................................................... 103
4.3.5 Sun Valley Lateral ...................................................................................................................... 105
4.3.6 Idaho Falls Lateral ...................................................................................................................... 107
4.3.7 Summary ................................................................................................................................... 110
4.4 Load Demand Curves ......................................................................................................................... 112
4.4.1 Customer Growth Summary Observations – Design Weather – All Scenarios ......................... 113
4.4.2 Core Customer Distribution Sendout Summary – Design and Normal Weather – All Scenarios
115
4.4.3 Projected Capacity Deficits – Design Weather – All Scenarios .................................................. 119
4.4.4 2021 IRP vs. 2023 IRP Common Year Comparisons................................................................... 122
4.5 Resource Optimization ....................................................................................................................... 133
4.5.1 Introduction ............................................................................................................................... 133
4.5.2 Functional Components of the Model ...................................................................................... 134
4.5.3 PLEXOS® Optimization Model ................................................................................................... 134
4.5.4 Model Structure ........................................................................................................................ 135
4.5.5 Demand Area Forecasts ............................................................................................................ 136
4.5.6 Supply Resources ....................................................................................................................... 139
4.5.7 Transport Resources .................................................................................................................. 141
4.5.8 Model Operation ....................................................................................................................... 142
4.5.9 Special Constraints .................................................................................................................... 143
4.5.10 Model Inputs ......................................................................................................................... 143
4.5.11 Model Results........................................................................................................................ 145
4.5.12 Summary ............................................................................................................................... 148
4.6 Planning Results ................................................................................................................................. 148
4.6.1 Overview.................................................................................................................................... 148
4.6.2 Distribution System Planning .................................................................................................... 149
4.6.3 Upstream Modeling ................................................................................................................... 154
4.6.4 Conclusion ................................................................................................................................. 156
4.7 Non-Utility LNG Forecast ................................................................................................................... 156
4.7.1 Introduction ............................................................................................................................... 156
4.7.2 History ....................................................................................................................................... 157
4.7.3 Method of Forecasting .............................................................................................................. 157
4.7.4 Benefits to Customers ............................................................................................................... 158

Integrated Resource Plan 2023 – 2028 vi

4.7.5 2021 Plant Downtime ................................................................................................................ 159
4.7.6 On-Going Challenges ................................................................................................................. 159
4.7.7 Safeguards ................................................................................................................................. 160
4.7.8 Future ........................................................................................................................................ 160
4.7.9 Recommendation ...................................................................................................................... 161
4.8 Infrastructure Replacement ............................................................................................................... 162
4.8.1 American Falls Neely Bridge Snake River Crossing .................................................................... 162
4.8.2 Rexburg Snake River Crossing ................................................................................................... 162
4.8.3 System Safety and Integrity Program (SSIP) .............................................................................. 163
4.8.4 Transmission Re-Confirmation .................................................................................................. 165
4.8.5 Shorted Casing Replacement or Abandonment Program (SCRAP) ........................................... 166
5 Glossary ...................................................................................................... 167

List of Tables
Table 1: Forecast New Customers..................................................................................................................... 15
Table 2: Forecast 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 ...................................................................... 37
Table 6: Large Volume Therm Forecast - Low Growth Scenario ....................................................................... 38
Table 7: Storage Resources ............................................................................................................................... 55
Table 8: Northwest Pipeline Transport Capacity .............................................................................................. 57
Table 9: 2020 - 2022 Billing and Meter Audit Results ....................................................................................... 69
Table 10: Five-Year Planning and Timing of Capacity Enhancements Selected .............................................. 111
Table 11: Idaho Falls Lateral Design Weather – Annual Core + LV-1 Market Distribution Sendout (Dth)...... 115
Table 12: Idaho Falls Normal Weather - Annual Core + LV-1 Market Distribution Sendout (Dth) ................. 115
Table 13: Sun Valley Design Weather - Annual Core + LV-1 Market Distribution Sendout (Dth) ................... 115
Table 14: Sun Valley Normal Weather - Annual Core + LV-1 Market Distribution Sendout (Dth) .................. 116
Table 15: Canyon County Design Weather - Annual Core + LV-1 Market Distribution Sendout (Dth) ........... 116
Table 16: Canyon County Normal Weather - Annual Core + LV-1 Market Distribution Sendout (Dth) .......... 116
Table 17: State Street Design Weather - Annual Core + LV-1 Market Distribution Sendout (Dth) ................ 117
Table 18: State Street Normal Weather - Annual Core + LV-1 Market Distribution Sendout (Dth) ............... 117
Table 19: Central Ada Design Weather - Annual Core + LV-1 Market Distribution Sendout (Dth) ................. 117
Table 20: Central Ada Normal Weather - Annual Core + LV-1 Market Distribution Sendout (Dth) ............... 118
Table 21: Total Company Design Weather - Annual Core + LV-1 Market Distribution Sendout (Dth) ........... 118
Table 22: Total Company Normal Weather - Annual Core + LV-1 Market Distribution Sendout (Dth) .......... 118
Table 23: Idaho Falls Design Weather - Peak Day Deficit Under Existing Resources (Dth)............................. 119

Integrated Resource Plan 2023 – 2028 vii

Table 24: Sun Valley Design Weather - Peak Day Deficit Under Existing Resources (Dth) ............................. 119
Table 25: Canyon County Design Weather - Peak Day Deficit Under Existing Resources (Dth) ..................... 120
Table 26: State Street Design Weather - Peak Day Deficit Under Existing Resources (Dth) ........................... 120
Table 27: Central Ada Design Weather - Peak Day Deficit Under Existing Resources (Dth) ........................... 121
Table 28: Total Company Design Weather - Peak Day SENDOUT (Core+LV-1) Deficit Under Existing Resources
(Dth) ................................................................................................................................................................ 121
Table 29: 2023 IRP Load Demand Curve – TC Usage Design Base Case (Dth) ................................................ 122
Table 30: 2021 IRP Load Demand Curve – TC Usage Design Base Case (Dth) ................................................ 122
Table 31: 2023 IRP Load Demand Curve – TC Usage Design Base Case .......................................................... 123
Table 32: 2023 IRP Peak Day Firm Delivery Capability (Dth) .......................................................................... 123
Table 33: 2021 IRP Peak Day Firm Delivery Capability (Dth) .......................................................................... 124
Table 34: 2023 IRP Peak Day Firm Delivery Capability .................................................................................... 124
Table 35: 2023 IRP Load Demand Curve – IFL Usage Design Base Case (Dth) ................................................ 125
Table 36: 2021 IRP Load Demand Curve – IFL Usage Design Base Case (Dth) ................................................ 125
Table 37: 2023 IRP Load Demand Curve – IFL Usage Design Base Case Over/(Under) 2021 IRP (Dth) .......... 126
Table 38: 2023 IRP Load Demand Curve – SVL Usage Design Base Case (Dth) ............................................... 126
Table 39: 2021 IRP Load Demand Curve –SVL Usage Design Base Case (Dth) ................................................ 127
Table 40: 2021 IRP Load Demand Curve –SVL Usage Design Base Case (Dth) ................................................ 127
Table 41: 2023 IRP Load Demand Curve – CCA Usage Design Base Case (Dth) .............................................. 128
Table 42: 2021 IRP Load Demand Curve – CCA Usage Design Base Case (Dth) .............................................. 128
Table 43: 2023 IRP Load Demand Curve – CCA Usage Design Base Case Over/(Under) 2021 (Dth) .............. 129
Table 44: 2023 IRP Load Demand Curve – SSL Usage Design Base Case (Dth) ............................................... 130
Table 45: 2021 IRP Load Demand Curve – SSL Usage Design Base Case (Dth) ............................................... 130
Table 46: 2023 IRP Load Demand Curve – SSL Usage Design Base Case Over/(Under) 2021 (Dth) ............... 131
Table 47: 2023 IRP Load Demand Curve – CAC Usage Design Base Case (Dth) .............................................. 132
Table 48: 2021 IRP Load Demand Curve – CAC Usage Design Base Case (Dth) .............................................. 132
Table 49: 2023 IRP Load Demand Curve – CAC Usage Design Base Case Over/(Under) 2021 (Dth) .............. 133
Table 50: Transport Input Summary ............................................................................................................... 145
Table 51: Lateral Summary by Year ................................................................................................................ 146
Table 52: Annual Traditional Supply Resources Results ................................................................................. 146
Table 53: Annual Transportation Resources Results ...................................................................................... 147
Table 54: Nampa LNG Inventory Available for Non-Utility Sales .................................................................... 158

List of Figures
Figure 1: The IRP Process .................................................................................................................................... 4
Figure 2: Intermountain Gas System Map .......................................................................................................... 6
Figure 3: Base Case Forecast Growth by Area of Interest ................................................................................. 14
Figure 4: Customer Addition Forecast - Residential & Commercial .................................................................. 14
Figure 5: Annual Additional Customers - Base Case: 2019 IRP vs 2021 IRP ...................................................... 15
Figure 6: Forecasted Canyon County Residential Customers ........................................................................... 21
Figure 7: Forecasted Sun Valley Residential Customers ................................................................................... 21
Figure 8: Forecasted Idaho Falls Residential Customers ................................................................................... 22

Integrated Resource Plan 2023 – 2028 viii

Figure 9: Forecasted North of State St Residential Customers ......................................................................... 22
Figure 10: Forecasted Central Ada Residential Customers ............................................................................... 23
Figure 11: Forecasted Total Company Residential Customers ......................................................................... 23
Figure 12: Forecasted Canyon County Commercial Customers ........................................................................ 24
Figure 13: Forecasted Sun Valley Commercial Customers ................................................................................ 24
Figure 14: Forecasted Idaho Falls Commercial Customers ............................................................................... 25
Figure 15: Forecasted North of State St Commercial Customers ..................................................................... 25
Figure 16: Forecasted Central Ada Commercial Customers ............................................................................. 26
Figure 17: Forecasted Total Company Commercial Customers ........................................................................ 26
Figure 18: Design Heating Degree Days ............................................................................................................ 30
Figure 19: LV Therms - 2021 IRP Forecast vs Actuals ........................................................................................ 32
Figure 20: Natural Gas Sources ......................................................................................................................... 42
Figure 21: Natural Gas Consumption by Sector ................................................................................................ 43
Figure 22: Shale Gas Production Trend ............................................................................................................. 43
Figure 23: US Lower 48 States Shale Plays ........................................................................................................ 45
Figure 24: Supply Pipeline Map ......................................................................................................................... 46
Figure 25: Natural Gas Trade ............................................................................................................................ 49
Figure 26: Intermountain Price Forecast as of 03/1/2023 ................................................................................ 51
Figure 27: Intermountain Storage Facilities ...................................................................................................... 52
Figure 28: Pacific Northwest Pipelines Map ..................................................................................................... 58
Figure 29: Damage Rates per 1,000 Locates by Region: ................................................................................... 71
Figure 30: Intermountain Locate Requests by Region ...................................................................................... 71
Figure 31: Intermountain Total Damages by Region ........................................................................................ 72
Figure 32: Guidehouse Categories of Potential Savings ................................................................................... 77
Figure 33: Cumulative Net Achievable Potential Synopsis ............................................................................... 78
Figure 34 Cumulative Net Achievable Potential by Scenario ............................................................................ 79
Figure 35 Natural Gas Historic Accomplishments Compared to Past and Current Study Achievable .............. 80
Figure 36: Large Volume Website Login ........................................................................................................... 81
Figure 37: Natural Gas Usage History ............................................................................................................... 82
Figure 38: Cumulative Net Achievable Potential by Sector .............................................................................. 82
Figure 39: Peak Heating Degree Day ................................................................................................................. 91
Figure 40: Distribution System Planning Process Flow ..................................................................................... 96
Figure 41: Canyon County Limiter ................................................................................................................... 100
Figure 42: Ustick Phase III ............................................................................................................................... 101
Figure 43: State Street Capacity Limiter ......................................................................................................... 102
Figure 44: State Street Phase II Update .......................................................................................................... 103
Figure 45: Central Ada County Capacity Limiter ............................................................................................. 104
Figure 46: 12-inch South Boise Loop ............................................................................................................... 105
Figure 47: Sun Valley Lateral Capacity Limiter ................................................................................................ 106
Figure 48: Shoshone Compressor Station ....................................................................................................... 107
Figure 49: Idaho Falls Lateral Capacity Limiter ............................................................................................... 108
Figure 50: Idaho Falls Lateral Blackfoot Compressor ...................................................................................... 109
Figure 51: IGC Natural Gas Modeling System Map ......................................................................................... 135
Figure 52: IGC Laterals from Zone 24 .............................................................................................................. 137

Integrated Resource Plan 2023 – 2028 ix

Figure 53: Total Company Design Base 2023 .................................................................................................. 138
Figure 54: IGC Supply Model Example ............................................................................................................ 139
Figure 55: IGC Storage Model Example ........................................................................................................... 140
Figure 56: IGC DSM Model Example ............................................................................................................... 141
Figure 57: IGC Transport Model Example ....................................................................................................... 142
Figure 58: LDC Design Base Case – Canyon County Lateral ............................................................................ 149
Figure 59: LDC Design Base Case – State Street Lateral .................................................................................. 150
Figure 60: LDC Design Base Case – Central Ada Lateral .................................................................................. 151
Figure 61: LDC Design Base Case – Sun Valley Lateral .................................................................................... 152
Figure 62: LDC Design Base Case – Idaho Falls Lateral .................................................................................... 153
Figure 63: 2028 Design Base Case – Total Company ....................................................................................... 154
Figure 64: 2028 Design Base Case Shortfall Solution – Total Company .......................................................... 156

Intermountain Gas Company Introduction

Integrated Resource Plan 2023 – 2028 1

1 Introduction
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, with a population of roughly 1,404,000. Currently,
Intermountain serves approximately 412,500 total customers in 74 communities through
a system of over 13,300 miles of transmission, distribution and service lines. In 2020,
approximately 755 million therms were delivered to customers and over 260 miles of
transmission, distribution and service lines were added to accommodate new customer
additions and maintain service for Intermountain’s growing customer base.

Intermountain Gas Company Introduction

Integrated Resource Plan 2023 – 2028 2

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.
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.
Intermountain Gas Company Introduction

Integrated Resource Plan 2023 – 2028 3

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.

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.

Intermountain Gas Company Introduction

Integrated Resource Plan 2023 – 2028 4

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, is a sample of
the invitation to join the committee. Committee members have varied backgrounds in
regulation, economic development, and business.
For this IRP cycle, 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 three virtual meetings were held in 2023 between the months of May and August.
Included in Exhibit 1 are sample copies of the presentations from the meetings as well as
Figure 1: The IRP Process
Intermountain Gas Company Introduction

Integrated Resource Plan 2023 – 2028 5

the meeting minutes. Intermountain also built a website1 where the Company’s meeting
schedule, presentation, minutes, and a video recording of each IGRAC meeting can be
found.
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.

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.

1 See Integrated Resource Plan - Intermountain Gas Company (intgas.com)
Intermountain Gas Company Introduction

Integrated Resource Plan 2023 – 2028 6

Figure 2: Intermountain Gas System Map

Intermountain Gas Company Introduction

Integrated Resource Plan 2023 – 2028 7

About the Natural Gas Industry
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 is the cleanest fossil fuel. It burns efficiently, producing primarily heat and
water vapor. Natural gas has also led U.S. carbon emission reductions to 27-year lows, and
the U.S. Energy Information Administration projects that trend will continue.2 The
Environmental Protection Agency’s (EPA) “Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990 – 2021” reveals distribution systems owned and operated by local natural
gas utilities emit 8.4 percent of natural gas system CH4 emissions. These annual emissions
declined more than 69 percent from 1990 to 2020, as natural gas utility companies invested
an average of $95 million daily in infrastructure upgrades to add more than 815,100 miles
of pipelines to serve 22.3 million more customers over that period, increases of 56 percent
and 41 percent, respectively.3 Distribution system CO2 emissions in 2021 were 70 percent
lower than 1990 levels and 1 percent lower than 2020 emissions. Annual CO2 emissions
from this segment are less than 0.1 million metric tons of CO2-equivalent emissions
(MMTe) across the time series.4
Natural gas pipelines are the safest and most efficient mode of transportation, surpassing
rail and truck, according to the U.S. Department of Transportation. Pipeline incidents or
disruptions to natural gas service are rare because of the industry’s consistent focus on
safety and reliability.5 Intermountain considers safety and reliability at every stage, from
pipeline design to construction to ongoing maintenance.
Natural gas is affordable. Since 2008, the price of natural gas has fallen by about 37%
(adjusted for inflation). According to the American Gas Association, households that use
natural gas for heating, cooking and clothes drying save an average of $1,068 per year
compared to homes using electricity for those applications.6 The American Gas
Association also reported that for residential customers, the cost of natural gas has been

2 https://www.aga.org/wp-content/uploads/2022/12/building-the-value-of-natural-gas-a-fact-base-may-2020.pdf 3 https://www.aga.org/research/reports/epa-updates-to-inventory-ghg/
4 https://www.aga.org/wp-content/uploads/2023/08/AGA-Report_Understanding-GHG-Emssions-from-Natural-Gas_2023.pdf
5 https://www.ingaa.org/File.aspx?id=28478
6 https://www.aga.org/wp-content/uploads/2023/04/Quick-gas-facts-sheet-2021.pdf
Intermountain Gas Company Introduction

Integrated Resource Plan 2023 – 2028 8

lower than the cost of propane, fuel oil, or electricity since 2010, and is forecasted to stay
low through 2040.7
According to the American Gas Association, in the United States natural gas currently meets
more than 33% of the nation’s energy needs, providing energy to almost 77 million
residential, commercial and industrial customers.8 Natural gas is now even more plentiful
than ever in North America, with an estimated 86 year supply at current consumption
levels.9 Even with this plentiful supply, however, it remains vital that all natural gas
customers use the energy as wisely and as efficiently as possible.

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 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 roughly 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

7 https://www.aga.org/natural-gas/affordable/
8 https://www.aga.org/wp-content/uploads/2023/04/Quick-gas-facts-sheet-2021.pdf
9 https://www.eia.gov/tools/faqs/faq.php?id=58&t=8
Intermountain Gas Company Introduction

Integrated Resource Plan 2023 – 2028 9

region, which according to Idaho Power’s 2020 annual report is approximately 5,463,000
MWh. 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 Plan
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 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.
Under the Company’s current RNG Facilitation Plan, Intermountain’s customers are
completely insulated from any risk that may be inherent in the developing industry. RNG
producers pay all of the upfront costs of constructing the facilities to interconnect the
RNG production facilities with Intermountain’s distribution system. RNG producers also
Intermountain Gas Company Introduction

Integrated Resource Plan 2023 – 2028 10

pay a monthly O&M fee that covers all O&M costs that are incurred in providing
transportation service to the RNG facilities. Insulating customers from potential risk, while
helping to grow an industry that could provide a supply resource in the future creates
significant benefits to all parties involved.

Intermountain Gas Company Demand

Integrated Resource Plan 2023 – 2028 11

2 Demand

2.1 Demand Forecast Overview
The first step in resource planning is forecasting future load requirements. Three essential
components of the load forecast include projecting the number of customers requiring
service, forecasting the weather sensitive customers’ response to temperatures and
estimating the weather those customers may experience. To complete the demand forecast,
contracted maximum deliveries to industrial customers are also included.
Intermountain’s long range demand forecast incorporates various factors including
divergent customer forecasts, statistically based gas usage per customer calculations, and
varied weather profiles, all of which are discussed later in this document. Using various
combinations of these factors results in six separate and diverse demand forecast scenarios
for the weather sensitive core market customers.
Combining those projections with the large volume market forecast provides
Intermountain with six total company demand scenarios that envelop a wide range of
potential outcomes. These forecasts not only project monthly and annual loads but also
predict daily usage including peak demand events. The inclusion of all this detail allows
Intermountain to evaluate the adequacy of its supply arrangements and delivery under a
wide range of demand scenarios.
Intermountain’s resource planning looks at distinct segments (i.e., Areas of Interest
(AOIs)) within its current distribution system as depicted in Figure 2 on page 6. After
analyzing resource requirements at the segment level, the data is aggregated to provide a
total company perspective. The AOIs for planning purposes are as follows:
• The Canyon County Area (CCA), which serves core market customers in Canyon
County.
• The Sun Valley Lateral (SVL), which serves core market customers in Blaine and
Lincoln counties.
• The Idaho Falls Lateral (IFL), which serves core market customers in Bingham,
Bonneville, Fremont, Jefferson, and Madison counties.
• The Central Ada County (CAC), which serves core market customers in the area of
Ada County between Chinden Boulevard and Victory Road, north to south, and
between Maple Grove Road and Black Cat Road, east to west.
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Integrated Resource Plan 2023 – 2028 12

• The State Street Lateral (SSL), which serves core market customers in the area of
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.
The All Other segment, which serves core market customers in Ada County not included
in the State Street Lateral and 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.

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 2023 through 2028. This forecast
provides the anticipated magnitude and direction of Intermountain’s residential and
commercial customer growth by the identified Areas of Interest 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 ARIMA model which incorporates population and
employment forecasts as an explanatory variable for the residential and commercial
customer forecasts, respectively. An ARIMA model is an autoregressive integrated moving
average model that is used on time series data to better predict future points. The
population data measures actual and forecasted population growth in Intermountain’s
service territory by county. The employment data measures actual and forecasted full- and
part-time jobs by place of work. Generally, when population increases, residential
customer counts are also increasing, thus, the reason for including population as an
explanatory variable. Similarly, when employment is increasing, commercial customer
counts are also increasing, thus, the reason for including employment as an explanatory
variable. Each County in Intermountain’s service territory is modeled separately.
The residential customer forecast model is as follows:
𝑅𝑅𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶= 𝛼𝛼0 + 𝛼𝛼1𝑃𝑃𝑃𝑃𝑝𝑝𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶+𝐴𝐴𝑅𝑅𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴(𝑝𝑝,𝑑𝑑,𝑞𝑞)

Where:
• 𝑅𝑅𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶=𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑑𝑑𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 𝐶𝐶𝐶𝐶𝑅𝑅𝑅𝑅𝑃𝑃𝐶𝐶𝑅𝑅𝐶𝐶𝑅𝑅 𝑏𝑏𝑏𝑏 𝐶𝐶𝑃𝑃𝐶𝐶𝑅𝑅𝑅𝑅𝑏𝑏
Intermountain Gas Company Demand

Integrated Resource Plan 2023 – 2028 13

• 𝑃𝑃𝑃𝑃𝑝𝑝𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶=𝑃𝑃𝑃𝑃𝑝𝑝𝐶𝐶𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑃𝑃𝑅𝑅 𝑏𝑏𝑏𝑏 𝐶𝐶𝑃𝑃𝐶𝐶𝑅𝑅𝑅𝑅𝑏𝑏
• 𝐴𝐴𝑅𝑅𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴(𝑝𝑝,𝑑𝑑,𝑞𝑞)=𝐴𝐴𝑅𝑅𝑑𝑑𝑅𝑅𝐼𝐼𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 𝑅𝑅ℎ𝑅𝑅𝑅𝑅 𝑅𝑅ℎ𝑅𝑅 𝐶𝐶𝑃𝑃𝑑𝑑𝑅𝑅𝑅𝑅 ℎ𝑅𝑅𝑅𝑅 𝑝𝑝 𝑅𝑅𝐶𝐶𝑅𝑅𝑃𝑃𝐶𝐶𝑅𝑅𝑡𝑡𝐶𝐶𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑡𝑡𝑅𝑅 𝑅𝑅𝑅𝑅𝐶𝐶𝐶𝐶𝑅𝑅,𝑑𝑑 𝑑𝑑𝑅𝑅𝑑𝑑𝑑𝑑𝑅𝑅𝐶𝐶𝑅𝑅𝑅𝑅𝐼𝐼𝑅𝑅 𝑅𝑅𝑅𝑅𝐶𝐶𝐶𝐶𝑅𝑅,𝑅𝑅𝑅𝑅𝑑𝑑 𝑞𝑞 𝐶𝐶𝑃𝑃𝑡𝑡𝑅𝑅𝑅𝑅𝑡𝑡 𝑅𝑅𝑡𝑡𝑅𝑅𝐶𝐶𝑅𝑅𝑡𝑡𝑅𝑅 𝑅𝑅𝑅𝑅𝐶𝐶𝐶𝐶𝑅𝑅

The commercial customer forecast model is as follows:
𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶= 𝛼𝛼0 + 𝛼𝛼1𝐸𝐸𝐶𝐶𝑝𝑝𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶+𝐴𝐴𝑅𝑅𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴(𝑝𝑝,𝑑𝑑,𝑞𝑞)

Where:
• 𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶=𝐶𝐶𝑃𝑃𝐶𝐶𝐶𝐶𝑅𝑅𝐶𝐶𝐼𝐼𝑅𝑅𝑅𝑅𝑅𝑅 𝐶𝐶𝐶𝐶𝑅𝑅𝑅𝑅𝑃𝑃𝐶𝐶𝑅𝑅𝐶𝐶𝑅𝑅 𝑏𝑏𝑏𝑏 𝐶𝐶𝑃𝑃𝐶𝐶𝑅𝑅𝑅𝑅𝑏𝑏
• 𝐸𝐸𝐶𝐶𝑝𝑝𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶=𝐸𝐸𝐶𝐶𝑝𝑝𝑅𝑅𝑃𝑃𝑏𝑏𝐶𝐶𝑅𝑅𝑅𝑅𝑅𝑅 𝑏𝑏𝑏𝑏 𝐶𝐶𝑃𝑃𝐶𝐶𝑅𝑅𝑅𝑅𝑏𝑏
• 𝐴𝐴𝑅𝑅𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴(𝑝𝑝,𝑑𝑑,𝑞𝑞)=𝐴𝐴𝑅𝑅𝑑𝑑𝑅𝑅𝐼𝐼𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 𝑅𝑅ℎ𝑅𝑅𝑅𝑅 𝑅𝑅ℎ𝑅𝑅 𝐶𝐶𝑃𝑃𝑑𝑑𝑅𝑅𝑅𝑅 ℎ𝑅𝑅𝑅𝑅 𝑝𝑝 𝑅𝑅𝐶𝐶𝑅𝑅𝑃𝑃𝐶𝐶𝑅𝑅𝑡𝑡𝐶𝐶𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑡𝑡𝑅𝑅 𝑅𝑅𝑅𝑅𝐶𝐶𝐶𝐶𝑅𝑅,𝑑𝑑 𝑑𝑑𝑅𝑅𝑑𝑑𝑑𝑑𝑅𝑅𝐶𝐶𝑅𝑅𝑅𝑅𝐼𝐼𝑅𝑅 𝑅𝑅𝑅𝑅𝐶𝐶𝐶𝐶𝑅𝑅,𝑅𝑅𝑅𝑅𝑑𝑑 𝑞𝑞 𝐶𝐶𝑃𝑃𝑡𝑡𝑅𝑅𝑅𝑅𝑡𝑡 𝑅𝑅𝑡𝑡𝑅𝑅𝐶𝐶𝑅𝑅𝑡𝑡𝑅𝑅 𝑅𝑅𝑅𝑅𝐶𝐶𝐶𝐶𝑅𝑅

Exhibit 2 shows the Company’s residential and commercial customer forecast.
Similar to the 2021 IRP, which demonstrated a continued resurgence in the housing market
Intermountain’s growth projections continue to stay strong. The following graph (Figure
3) depicts the relationship, or shape, of customer additions by AOI:
Intermountain Gas Company Demand

Integrated Resource Plan 2023 – 2028 14

Figure 3: Base Case Forecast Growth by Area of Interest

The forecast contains three economic scenarios: base case, low growth, and high growth.
IGC has incorporated these scenarios into the customer growth model and has developed
three five-year core market customer growth forecasts. The following graph (Figure 4)
shows the annual additional customer forecast for each of the three economic scenarios.

Figure 4: Customer Addition Forecast - Residential & Commercial
The following graph (Figure 5) shows the difference in base case annual additional
customers between the 2021 and 2023 IRP forecast years common to both studies:
0
500
1,000
1,500
2,000
2,500
3,000
3,500
Ad
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C
u
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t
o
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Base Case Forecast Growth by Area of Interest
2023 2024 2025 2026 2027 2028
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
Ad
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C
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t
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Customer Addi�on Forecast
Residen�al & Commercial
Low Growth Base Case High Growth
Intermountain Gas Company Demand

Integrated Resource Plan 2023 – 2028 15

Figure 5: Annual Additional Customers - Base Case: 2019 IRP vs 2021 IRP

The following tables show the results from the five-year customer growth model for each
scenario for the annual additional or incremental customers and total customers at each
year- end.
Table 1: Forecast New Customers

GROWTH
5,229 6,557 8,156 9,077 9,229 8,557
11,004 11,030 11,018 11,011 11,020 11,017
GROWTH
16,418 15,379 14,347 12,911 12,770 12,720

Table 2: Forecast Total Customers

GROWTH
409,167 415,724 423,880 432,957 442,185 450,742
414,942 425,972 436,990 448,001 459,021 470,038
GROWTH
420,356 435,735 450,082 462,994 475,763 488,484
10,200
10,400
10,600
10,800
11,000
11,200
11,400
11,600
11,800
Ad
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C
u
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Annual Addi�onal Customers
Base Case: 2021 IRP vs 2023 IRP
2021 IRP 2023 IRP
Intermountain Gas Company Demand

Integrated Resource Plan 2023 – 2028 16

The following sections explore more fully the different components of the customer
forecast, including the ‘22 Forecast, market penetration and conversion rates, and
commercial customer growth.

2.2.1 The Base Case Economic Growth Scenario
Intermountain utilized the 2022 Woods & Poole (W&P) State and County Projections for
the base case economic growth scenario. W&P projected that Idaho will continue to be an
attractive environment for future economic, population and household growth. In the
decade of the 1990s Idaho's population increased at a strong annual average rate of 2.5
percent per year. The Great Recession of 2008 caused a significant slowing in Idaho's
economy. The 2008 recession caused Idaho’s nonagricultural employment to contract by
nearly 51,500 jobs (7.9%) in the years 2008 through 2010.
As the recession took hold in Idaho the state did not immediately experience a slowdown
in population growth which averaged 1.9% per year over the 2000 to 2010 period.
Nevertheless, population growth slowed to a pace of less than 1.0% per year in 2011 and
2012.
Nonagricultural employment in Idaho regained its upward momentum in 2011 with an
annual average increase of 1.2% - 7,200 jobs. In the years 2012 – 2019 Idaho’s
nonagricultural employment gains were strong with an annual average increase of 2.9% per
year, a gain of 137,500 jobs over the 7-year period.
In 2020 the COVID-19 pandemic brought Idaho’s economic growth to a halt.
Nonagricultural employment in Idaho declined 74,000 jobs between February 2020 and
April 2020. However, in the following months Idaho regained many of those jobs that
were lost. So much so that the state’s November 2020 total employment numbers were
down only 7,200 jobs from year earlier levels. While the November 2020 number of
persons unemployed in Idaho was nearly 25,000 above year earlier levels the sum of the
number of employed plus the unemployed is indicative of an economy that continues to
exhibit an underlying upward momentum and future growth.
While Idaho’s economy may not post the gains seen in the 2015 to 2019 period in 2021
and 2022 it is forecasted to continue its economic gains over the longer term 2023 to 2045
forecast period.
Total non-agricultural employment in the State is projected to increase by 393,000 (an
annual average increase of 1.4 percent per year) over the 2023 to 2045 period. Ada and
Intermountain Gas Company Demand

Integrated Resource Plan 2023 – 2028 17

Canyon counties are projected to capture the majority of the non-ag employment gains
with a projected increase of 226,400 non-ag jobs in the two counties, an annual average
increase of 1.8 percent per year over the 2023 to 2045 period. During those twenty-five
years Ada and Canyon counties are projected to account for nearly 57.6 percent of the
projected total non-ag employment gains statewide. Other areas of projected employment
growth are in Bannock, Bonneville, Jefferson, and Madison counties of Eastern Idaho.
Over the 2023 to 2045 forecast period non-ag employment in these the Eastern Idaho
counties is projected to increase by 55,100 jobs, a 1.3 percent annual average increase.
As has been the case over the last two decades, employment and population growth in the
state is projected to be concentrated in the few, more urban, counties. Ada and Canyon
counties will continue to capture over 60 percent of the state’s projected future
employment and population growth. In second place Kootenai and Bonner counties in
North Idaho are projected to capture nearly 20% of the 2023 to 2045 employment and
population growth. And the Eastern Idaho counties along Intermountain Gas Company’s
Idaho Falls Lateral (Bannock, Bingham, Bonneville, Butte, Fremont, Jefferson, Madison,
and Power counties) are projected to account for nearly 12 percent of future employment
and population gains in the state.
Idaho's manufacturing industries will not be the driver of future economic growth in the
state. In the years 2000 to 2010 manufacturing employment in Idaho decreased by nearly
17,200 jobs. In what can only be considered as a somewhat remarkable turnaround in the
years since 2010, and through mid-year 2020 Idaho regained nearly 14,000 manufacturing
jobs. In the 2023 to 2045 forecast period, manufacturing employment is projected to
increase by only 9,200 jobs.
Employment in Idaho's forestry, fishing, and related activities sector slipped in the 2008
Great Recession. It has not recovered and its unlikely that it will recover with the possible
exception of the production of higher value-added processed wood products. Future job
gains in the forestry, fishing, and related activities sector is projected to be minimal over
the 2023 to 2045 forecast period.
Statewide employment in the Transportation, Trade, and Utilities industries is projected to
increase by nearly 35,000 jobs over the 2023 to 2045 forecast period; an annual average
increase 0of nearly 1.0 percent per year. In general, employment in Transportation, Trade,
and Utilities is projected to increase at a pace that is slower than the forecasted rate of
population and household growth statewide. In Ada and Canyon counties Transportation,
Trade, and Utilities employment is projected to increase by 23,100 over the forecast period,
representing 66.0 percent of the projected statewide employment gains in the sector.
Intermountain Gas Company Demand

Integrated Resource Plan 2023 – 2028 18

The service industries in Idaho have been the fastest growing in terms of employment gains
over the last twenty years. In the last 10 years, accommodation and food services
employment has increased about 20,000 jobs in Idaho, even with a large disruption due to
the COVID-19 pandemic. Accommodation and food services industries are the largest part
of the leisure and hospitality sector and given Idaho’s population and increased tourism,
employment will continue to rise. In the 2023 to 2045 forecast period, accommodation
and food services employment is projected to increase by 37,000 jobs in Idaho. Idaho
employment in the Professional and Technical Services sector increased by nearly 26,000
jobs over the last 20 years; an annual average increase of 2.4 percent per year. Ada and
Canyon counties captured nearly 66.7 percent of the State’s Professional and Business
Services employment growth from that time period. In the 2020 to 2045 forecast period
Professional and Business Services employment is projected to increase by 41,300; an
annual average compound rate of 2.1 percent per year. Historically the Professional and
Technical Services sector in Idaho has posted employment gains and losses that could be
considered volatile. This has been due to the business classification of subcontractors
utilized by the US Department of Energy at the Idaho National Laboratory (INL). Changes
in INL subcontractors have caused Professional and Business Services employment in the
state to change rapidly in the past and they may change in the future.
Idaho employment in Educational and Health Services increased by nearly 67,000 jobs over
the previous 20 years; an annual average increase of 3.2 percent per year. Ada and Canyon
counties captured 31,900, nearly 47.6 percent, of the state’s Educational and Health
Services employment growth over the previous 20 years. In the 2023 to 2045 forecast
period Educational and Health Services employment is projected to increase by 118,500;
an annual average compound rate of 2.7 percent per year. Jobs in Idaho’s Educational and
Health Services sector are more spatially diverse that the Professional and Business Services
sector. Almost every county in Idaho is projected to post an increase in employment over
the 2023 to 2045 forecast period. In the counties along Intermountain Gas Company’s
Idaho Falls Lateral the Educational and Health Services sector is projected add 19,800 jobs
over the 2023 to 2045 forecast period.
Idaho employment in Arts, Entertainment, & Recreation sector added 10,300 jobs over
the last 20 years; an annual average increase of 2.7 percent per year. Ada and Canyon
counties captured 5,700, nearly 55.6 percent, of the state’s Arts, Entertainment, &
Recreation employment growth. In the 2023 to 2045 forecast period Leisure and
Hospitality Services employment is projected to increase by 15,300; an annual average
compound rate of 2.1 percent per year.
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Employment in the Government sector increased by 16,700 jobs over the last 20 years; an
annual average increase of 0.8 percent per year. Government employment gained 10,500
jobs in Ada and Canyon counties over that same time period, a reflection of the faster than
average population and household growth in the two counties which has caused significant
increases in local government employment. In the 2023 to 2045 forecast period
Government employment is projected to increase by 20,100; an annual average compound
rate of 0.7 percent per year. No specific growth assumptions are made concerning
government future employment at Idaho’s two largest government facilities – Mountain
Home Air Force Base and the INL.

2.2.2 Population and Household Growth
US Census Bureau population estimates indicate that Idaho has experienced a significant
increase in population growth since the end of the 2008 Great Recession. Over the years
2014 through 2019, population growth in Idaho was twice ranked as the fastest growing in
the nation, and in every year of the last five years Idaho was always ranked one of the
fastest growing states in the country. The COVID – 19 pandemic did not slow down
Idaho’s population growth. Per the US Census Bureau, Idaho was ranked as the fastest
growing state in the nation during 2020. This has only continued into 2021 and 2022, as
Idaho’s population grew 2.98% and 1.82%, respectively. Idaho was the fastest growing
state in 2020 and 2021, and the second fastest growing state in 2022.
Total population in Idaho has increased at a robust pace since 2010. Through 2019 the US
Census Bureau estimates that Idaho’s population increased by 219,500 (14.0% - a annual
average increase of 2.0% per year over the 2010 to 2019 period). These increases are
overwhelmingly due to a robust in-migration to Idaho. A 2.0% annual average rate of
population growth, minus a natural population growth rate of 0.42% per year, leaves an
annual average population increase of 1.58% per year (about 28,000 persons per year) due
to in-migration.
In five years after the effects of the 2008 Great Recession (2014 – 2019), Idaho’s population
increased by 136,000, an overall increase of 8.2 percent. Ada and Canyon counties
accounted for 53.6 percent of the state’s population growth over those five years. Idaho’s
population growth over the 2014 through 2019 period was very concentrated. If population
growth in the Eastern Idaho counties of Bannock, Bonneville, Jefferson, and Madison are
included these six counties represent 66.4 percent of the state’s population growth. Add in
the population growth in Twin Falls County and that share increases to 70.2 percent. Lastly,
adding in the population growth that occurred in Kootenai and Bonner counties in North
Idaho and these nine counties accounted for 85.3 percent of the state’s population growth
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over the 2014 to 2019 period. That concentration of the state’s population growth is
projected to continue in the forecast period.
It is projected that during the 2023 to 2045 forecast period Idaho's population will increase
by 500,000 reaching a total population of 2,444,700 by the year 2045, an annual average
pace of 1 percent per year. The number of households in the state is expected to increase
by approximately 186,200 over the 2023 to 2045 forecast period.
Ada and Canyon counties are projected to capture the majority of Idaho’s population
growth over the forecast period. Population in Ada and Canyon counties are projected to
reach 718,400 and 349,300, respectively, by the year 2045. This represents an increase of
190,300 in Ada County population and a 97,900 increase in Canyon County population
over the 2023 to 2045 forecast period. In total, population growth in Ada and Canyon
counties are projected to account for 57.6 percent of the 2023 to 2045 projected population
growth in the state.
In Eastern Idaho, Bonneville, Madison, Bannock, and Jefferson counties are expected to
see increases in population of 33,600, 16,600, 8,900 and 10,200, respectively, a total
population increase for the four counties of 69,400 over the 2023 to 2045 forecast period.
These four Eastern Idaho counties are projected to account for 13.9 percent of the state’s
population growth over the forecast period.

2.2.3 The High and Low Economic Growth Scenarios
The high growth and low growth scenarios utilize the confidence intervals for each model
to build the high and low customer growth scenarios. The confidence intervals capture
the high and low historical economic growth, and the impact it has to customer growth
through the regression models and provides an output in the case of a high and low
economic pathway.

2.2.4 Residential Customer Forecast
The following graphs show the forecasted residential customer counts based on the low
growth, base case and high growth scenarios for each AOI and Total Company using the
methodology explained previously.
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Figure 6: Forecasted Canyon County Residential Customers

Figure 7: Forecasted Sun Valley Residential Customers

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Figure 8: Forecasted Idaho Falls Residential Customers

Figure 9: Forecasted North of State St Residential Customers

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Figure 10: Forecasted Central Ada Residential Customers

Figure 11: Forecasted Total Company Residential Customers

2.2.5 Commercial Customer Forecast
The following graphs show the forecasted commercial customer counts based on the low
growth, base case and high growth scenarios for each AOI and Total Company using the
methodology explained previously.
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Figure 12: Forecasted Canyon County Commercial Customers

Figure 13: Forecasted Sun Valley Commercial Customers

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Figure 14: Forecasted Idaho Falls Commercial Customers

Figure 15: Forecasted North of State St Commercial Customers

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Figure 16: Forecasted Central Ada Commercial Customers

Figure 17: Forecasted Total Company Commercial Customers

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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 65°F (also called HDD65). As an example, if one
assumes a day where the mean outdoor temperature is 30°F, the resulting HDD65 would
be 35 (i.e. 65°F base minus the 30°F 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 2022. 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.
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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). 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 (P3) 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 overusing 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 the company-wide 50-year probability event, which was a 78
degree day, would be appropriate to use in the design weather model.

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2.3.4 Base Year Design Weather
To create a design weather year from the base year, some 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 five-day
moving average of the temperatures for the past thirty-year period to select the five coldest
consecutive 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 four 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 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. Therefore Intermountain does
not 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 on following page). This curve
provides a robust projection of the extreme temperatures that can occur in Intermountain’s
service territory.
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Figure 18: Design Heating Degree Days

The resulting Normal, Base Year (1985), and Design Year degree days by month are
outlined in Table 3 below:
Table 3: Monthly Heating Degree Days

Actual Heating Year
1985
Weighted Normal
(30 Year Rolling)
Design Year
October 604 452 603
November 827 809 836
December 1,338 1,103 1,338
January 1,483 1,109 1,749
February 1,180 861 1,180
March 972 688 974
April 413 484 414
May 231 253 226
June 62 91 63
July 0 3 0
August 36 10 39
September 306 123 299
Total 7,452 5,986 7,721
Monthly Heating Degree Days
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2.3.5 Area Specific Degree Days
As noted earlier in this IRP, Intermountain has identified certain Areas of Interest (AOI).
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. 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.

2.4 Large Volume Customer Forecast

2.4.1 Introduction
The Large Volume (LV) customer group is comprised of approximately 149 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 47% of Intermountain’s 2022 annual throughput and 24%
of the projected 2023 design Base Case peak day. Nearly 97% of 2022 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
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Integrated Resource Plan 2023 – 2028 32

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. The chart below (Figure 19) shows a comparison of total
actual LV therm use against base case forecast therm use from the 2021 IRP for the years
2021 – 2023.

Figure 19: LV Therms - 2021 IRP Forecast 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.

0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
2021 2022 2023
00
0
'
s

o
f

T
h
e
r
m
s
2021 IRP
Comparison of Large Volume Forest vs Actual
Actual 2021 IRP Forecast
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Integrated Resource Plan 2023 – 2028 33

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 149 existing and up to ten projected new
customers (per the High Growth scenario) were combined into six homogeneous market
segments:

2023 Customers by Market Segment:
• 18 potato processors
• 49 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
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Integrated Resource Plan 2023 – 2028 34

MDFQ and MDQ. Intermountain utilized LV customer CDs as they existed on January
1, 2023, for the beginning point for Base Case CDs.
While many LV customers are predicted to increase their annual usage requirements
through 2028, 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 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 Areas 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 but 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 importance, 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
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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 2022 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 20 million therms (or an annualized rate of 1.0%) as seen
in Table 4 below. The rate of projected annualized growth remains strong compared to
the last IRP largely due to growth in Other Food, Meat, Dairy and Agriculture.

Table 4: Large Volume Therm Forecast - Base Case Scenario

A. The Potato Processors group is projected to slightly increase over the forecast
period. One plant expansion is driving the increase. No new plants are assumed in
the forecast. Most of the plants in this group are looking for ways to lower the
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Integrated Resource Plan 2023 – 2028 36

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 projected to see some growth over the forecast
period. The growth is largely due to strong growth in sugar production and one new
plant in the forecast.

C. The Meat, Dairy and Ag segment is projected to see growth which largely reflects
the ramp up of several new meat plants and one new plant in the forecast.

D. The Chemical/Fertilizer production companies’ usage is expected to remain
relatively flat over the forecast period.

E. The Manufacturing companies’ usage is expected to remain relatively flat over the
forecast period.

F. The Institutional group is projected to have relatively flat growth, with the addition
of a new hospital in the forecast.

G. The usage in the Other group is projected to see some strong growth largely due to
customers using natural gas as part of their process to produce renewable natural
gas.

2.4.9 High Growth Forecast Summary
The High Growth forecast incorporates adjustments for additional growth that would
occur if inflation trended at a lower rate than that experienced in the past eighteen months
and the economy has continued growth. The scenario assumes very competitive natural
gas prices compared to other alternatives. Projected sales in year 2024 of the High Growth
forecast of 418.1 million therms is approximately 3.7% above Base Case. By 2028 the High
Growth scenario’s annual sales grow to 438.3 million therms an increase of 28.3 million
therms (6.9%) over 2028 Base Case. The following table summarizes the High Growth
changes over the forecast period:

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Table 5: Large Volume Therm Forecast - High Growth Scenario

A. The Potato Processors group is projected to slightly increase over the forecast
period. One plant expansion is driving the increase. No new plants are assumed in
the 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. Other Food Processors growth is projected to be strong as demand for sugar, frozen
foods and other vegetable continues to grow. This scenario assumes 2 new
customers will come online during the forecast period.

C. The Meat, Dairy and Ag group is projected to show very strong growth as existing
facilities expand and several new meat producers ramp up. Two new dairy
processors are part of this high growth forecast period.

D. The Chemical/Fertilizer group’s gas usage is anticipated to increase only slightly
over the five-year period.

E. The Manufacturing group is projected to have a slight growth over the forecast
period reflecting increases in electronics and building-related industries. This
scenario assumes the addition of one manufacturing related facility.

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.

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G. Growth is expected to be strong in the Other segment as the increase for traditional
natural gas in 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-à-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. Declines are
expected in manufacturing and the Other segment is expected to fall as the renewable fuels
market declines and compressed natural gas (CNG) markets are replaced by electric
vehicles (EVs) as well as ethanol production decreases. Projected sales in year 2024 of the
Low Growth Scenario are approximately 3.4% below the Base Case but by 2028 are
projected sales are 21.6 million therms (5.2%) under Base Case. The following table
summarizes the Low Growth changes over the forecast period:

Table 6: Large Volume Therm Forecast - Low Growth Scenario

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. The Other Food Processor group is expected to remain steady. Existing facilities
will remain flat.

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C. The Meat and Dairy group is projected to increase over the period as demand for
meat and dairy is expected to grow.

D. The Chemical/Fertilizer segment is forecast with a small increase in gas usage.

E. The Manufacturing group is also projected to slightly decrease over the period by
0.1% reflecting some strength in the high tech/electronics.
F. The institutional group is projected to also show slowing growth that would lead to
a small increase in annual gas use.

G. At least one very large fuels facility in the Other group is projected to go out of
business and other customers using natural gas to power fleets of vehicles are
assumed to begin the move to electric fleets as well as no new renewable natural gas
facilities forecasted to come on.
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Integrated Resource Plan 2023 – 2028 40

3 Supply and Delivery Resources

3.1 Overview
Once future load requirements have been forecast, 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 Areas of Interest (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, beginning on page Error! Bookmark not
defined., demand and capacity are compared to 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.

3.2 Traditional Supply Resources

3.2.1 Overview
Natural gas is a fundamental fuel for Idaho’s economic and environmental future: heating
our homes, powering businesses, moving vehicles, and serving as a key component in many
of our 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
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Integrated Resource Plan 2023 – 2028 41

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 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.
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.
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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).

Figure 20: Natural Gas Sources
Source: EIA AEO2021

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 on
the following page for consumption by sector, 2000-2050.

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Figure 21: Natural Gas Consumption by Sector
Source: EIA AEO2023

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 through 2050.

Figure 22: Shale Gas Production Trend
Source: EIA AEO2021

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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 tend 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.

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 on the following
page identifies the shale plays in the lower 48 states.
Per the EIA, the portion of U.S. energy consumption supplied by domestic production
decreased in 202010, in large part due to responses to the COVID-19 pandemic. “Demand
for energy delivered to the four U.S. end-use sectors (residential, commercial,
transportation, and industrial) decreased to 90% of its 2019 level in 2020; a steeper decline

10 https://www.eia.gov/outlooks/aeo/pdf/AEO_Narrative_2021.pdf
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than seen in real GDP. Compared with the financial crisis of 2008, the COVID-19-related
decline in the total demand for delivered energy is about 70% larger. In the AEO2021
Reference case, EIA projects that U.S. energy demand takes until 2029 to return to 2019
levels.”

Figure 23: US Lower 48 States Shale Plays
Source: Energy Information Administration based on data from various published studies.

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
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opportunity to procure some portion of its annual needs from supply basins which may
offer lower cost gas supplies in the future.
3.2.5.1 Alberta
Alberta supplies are delivered to Intermountain via two Canadian pipelines (TransCanada
Energy via NOVA Gas Transmission Ltd. (NOVA) and Foothills Pipelines Ltd.
(Foothills)) and two U.S. pipelines (Gas Transmission Northwest (GTN) and Williams
Northwest Pipeline (NWP)) as seen below in Figure 24.

Figure 24: Supply Pipeline Map
Source: Northwest Gas Association 2020 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.

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3.2.5.2 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 Regulator11 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. In recent
history BC pricing has risen dramatically, and it is no longer one of the lowest basins in the
nation. Front of month prices spiked to $45.25 for January of 2023, while day gas prices
exceeded $100/dth on some days. This was the result of a number of coinciding forces,
including the geopolitical turmoil in the Ukraine, inflationary economic pressure
domestically, and an extreme polar system landing in the pacific northwest in the days
before the end of 2022. In recent weeks there has been a dramatic fall from 2022 pricing
highs, led by what some are calling a correction to market overreaction to the forces
described above, a projected El Nino weather pattern contributing to warm heating season
forecasts, and higher than expected storage levels.
3.2.5.3 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

11 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.
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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 chosen today and for the foreseeable
future to purchase the predominance of its annual supply needs out of Alberta due to the
lower cost environment from that supply basin. 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.
3.2.5.4 Export LNG
Growth in North American natural gas supplies (see Shale Gas above) have 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.
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Figure 25: Natural Gas Trade
Source: EIA AEO2021

3.2.5.5 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.
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
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beginning of the month for monthly spot gas.
4. Winter Baseload: gas supply that is purchased for a 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.

3.2.5.6 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.

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Figure 26: Intermountain Price Forecast as of 03/1/2023

3.2.5.7 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 (see page Error!
Bookmark not defined.), 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 on following page). Intermountain also leases capacity from
Dominion Energy Pipeline’s Clay Basin underground storage field in Wyoming, and
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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.
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.

3.2.5.7.1.1 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
Figure 27: Intermountain Storage Facilities
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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.

3.2.5.7.2 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
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addition, commodity costs of injections and withdrawals are usually minimal by
comparison. The lower costs allow for 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.

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Table 7: Storage Resources

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
every-day transport capacity and term gas supplies during those off-peak months when the
core market loads are lower.

3.2.5.7.3 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 60 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.

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3.2.5.7.4 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.

3.2.6 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 by that 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 (other than Nampa LNG) via citygate taps with NWP. Table 8 on the following
page 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 NOVA 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.

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Table 8: Northwest Pipeline Transport Capacity

Quantity (MMBtu per
day)
2023 2024 2025 2026 2027 2028
Sumas Base Capacity 90,941 90,941 90,941 90,941 90,941 90,941
Sumas Segmentation
and Capacity Release (90,941) (90,941) (90,941) (90,941) (90,941) (90,941)
Capacity - - - - - -
and Capacity Release 111,941 111,941 111,941 111,941 111,941 111,941
Capacity 338,043 338,043 338,043 280,893 280,893 280,893
City Gate Supply 10,000
Total City Gate
Delivery Before TF-2 348,043 348,043 348,043 290,893 290,893 290,893
TF-2 Capacity -
-
Capacity 185,512 185,512 185,512 155,175 155,175 155,175
Nampa LNG
include Rexburg) 60,000 60,000 60,000 60,000 60,000 60,000
Total City Gate Delivery
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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 I-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).

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
Figure 28: Pacific Northwest Pipelines Map
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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 are in an increasingly mega-regional
marketplace where market conditions across the continent - including pipeline capacities -
can, and often do, affect regional supply availability and pricing dynamics. According to
the EIA, “In October, the natural gas spot price at Henry Hub averaged $5.51 per million
British thermal units (MMBtu), which was up from the September average of
$5.16/MMBtu and up from an average of $3.25/MMBtu in the first half of 2021. The
rising natural gas prices in recent months reflect U.S. natural gas inventory levels that are
below the five-year (2016–20) average. Despite high prices demand for natural gas for
electric power generation has remained relatively high, which along with strong global
demand for U.S. liquefied natural gas (LNG) has limited downward natural gas price
pressures.”12

3.2.7 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

12 https://www.eia.gov/outlooks/steo
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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 Model Section beginning on
page Error! Bookmark not defined.).

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 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 been 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
Key Points
• Capacity release allows
shippers to offer unused
capacity in an auction to
other shippers.
• Intermountain is an active
participant in capacity
releases, utilizing IGI
Resources to market the
capacity to other customers.
• 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
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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 712B, the rules and regulations around
capacity release transactions for interstate pipeline capacity were developed. These rules
cover such 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
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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, 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
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IGI or other third parties are always subject to recall should Intermountain have any need
for that capacity to serve its customers.

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 any time
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.
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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.

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
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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 BTUs per pound, which converts into 16-20 pounds of wood being burned to
produce one therm of natural gas.

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 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
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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.

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 three RNG producers on Intermountain’s distribution
system. All three 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. None of the RNG currently being
injected into Intermountain’s distribution system is being purchased for the Company’s
end use customers because of its expense relative to traditional natural gas.
However, 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
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RNG at $15/MMBtu, which was based on an American Gas Foundation report that states
“…many landfill gas projects are estimated to produce RNG at a cost of $10-20/MMBtu,
and dairy manure projects may produce RNG at a cost of closer to $40/MMBtu.”13
However, the report goes on to discuss an ICF report that describes substantial RNG
production volumes at prices lower than $20/MMBtu. Intermountain is assuming the price
of this renewable resource will continue to fall as the technology becomes more mature,
and thus settled on a price within the range of current landfill gas projects for all RNG.
Results of the RNG analysis are discussed in the Planning Results section.

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.”14 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
• Gray hydrogen: Hydrogen produced using natural gas to create steam without
capturing CO2;

“Green hydrogen, (which is considered one of the cleaner forms of hydrogen), produced
with renewable resources costs between about $3/kg and $6.55/kg, according to the
European Commission's July 2020 hydrogen strategy.”15 With a conversion rate for kg per

13 https://gasfoundation.org/wp-content/uploads/2019/12/AGF-2019-RNG-Study-Full-Report-FINAL-12-18-19.pdf 14 https://www.nrel.gov/docs/fy21osti/77610.pdf
15 https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/experts-explain-why-
green-hydrogen-costs-have-fallen-and-will-keep-falling-63037203
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MMBtu at 7.5, hydrogen prices range from about $22.5/dth to $49.12/dth. There 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”).16 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.

3.5 Lost and Unaccounted For Natural Gas Monitoring
Intermountain Gas Company 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 Intermountain’s distribution system and volumes of natural gas billed to
Intermountain’s customers. Intermountain is consistently one of the best performing
companies in the industry with a LAUF percentage of -0.48% over the period of July 2021
to June of 2022.
Intermountain 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
• Monitor ten 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 conducts billing audits to identify irregular usage with each billing cycle.
Intermountain 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.

16 https://www.energy.gov/eere/fuelcells/hydrogen-shot
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Intermountain 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.

Table 9: 2020 - 2022 Billing and Meter Audit Results

184 174 164
2 0 2
14 24 14
200 198 197

3.5.2 Meter Rotation and Testing
Meter rotations are also an important tool in keeping LAUF levels low. Intermountain
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, Intermountain also identifies the potential for
incorrectly sized and/or type of meter in use by our larger industrial customers.
Intermountain 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, Intermountain technicians check Intermountain’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,
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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 leads to unintentional excavation damage to our 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”.
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. 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.
Out recent efforts are aimed at educating the affected public and excavation contractors
on the importance of calling 811 prior to any type of digging. Intermountain Gas has
participated in a variety of informational activities, including sponsored events, general
awareness mailings, and multi-media advertising, as well 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 Intermountain Gas facilities
is still from excavation contractors or individuals not submitting a locate request with the
state one call center before digging. Intermountain Gas will continue to focus our public
awareness and damage prevention efforts on working with all excavation parties to increase
awareness of the importance to submit 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 Intermountain Gas underground facilities. Figure 29
shows the damage rate per 1,000 locates, Figure 30 shows locate requests by region and
Figure 31 shows the total locates for 2020 through 2022.

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Figure 29: Damage Rates per 1,000 Locates by Region:

Figure 30: Intermountain Locate Requests by Region

6.73
5.19
7.35
5.54
4.25
5.865.92
4.56
6.36
0
1
2
3
4
5
6
7
8
2020 2021 2022
DAMAGE RATE PER 1,000 -BY REGION
East Region West Region IGG Total
40,146 44,302 42,584
84,162 90,539 85,659
124,308 134,841 128,243
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
2020 2021 2022
LOCATE REQUESTS -BY REGION
East Region West Region IGC Total
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Figure 31: Intermountain Total Damages by Region

3.5.5 Weather and Temperature Monitoring
Intermountain 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
billing factors. Additionally, Intermountain utilizes hourly temperatures for a 24-hour
period, averaged into 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
Gas can be lost physically or on the Company’s records. For large line breaks as well as
relief valves that are open for an extended period of time, the volume of gas that is lost is
calculated. Gas is also released from the system and lost on small line breaks, venting reliefs
that don’t vent for an extended period, and during some maintenance activities, such as
installing new meters. Additionally, meter accuracies aren’t always 100% accurate and the
volume of gas that is measured at customer meters will never be the exact same as the
volume of gas measured at custody transfer meters. For gas lost, a line break charge is
applied based on the effective rate at the time of the break (WACOG + Gas Transportation
Costs. Intermountain 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.
270 230
313
466
385
502
736
615
815
0
100
200
300
400
500
600
700
800
900
2020 2021 2022
TOTAL DAMAGES -BY REGION
East Region West Region IGC Total
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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, over time, 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 allow
Intermountain to displace the need to purchase additional
gas supplies, delay contracting for incremental pipeline
capacity, and possibly negate or delay the need for
reinforcement 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.
Key Points
• Energy efficiency programs
acquire cost-effective
demand side resources in
order to save customers
energy and money.
• In its 2023 IRP, the
Company estimated DSM
therm savings based on the
Conservation Potential
Assessment (CPA)
commissioned by
Intermountain.
• The business as usual
(BAU) model is the model
used for the 2023 IRP base
case. The BAU scenario is
most closely aligned and
calibrated with historic
program activity based on
program accomplishments.
• Intermountain has modeled
three additional scenarios;
Unconstrained Historical
Budget, Medium Adoption,
and High Adoption, High
Incentive scenario.
• Cumulatively, Intermountain
projects the BAU case to
save customers 8.1 million
therms in 2028.

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3.6.2 Conservation Potential Assessment
In its 2023 IRP, the Company estimated DSM therm savings based on the Conservation
Potential Assessment (CPA), found in Exhibit 4, 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.
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.

3.6.3 Market and Measure Characterization
As a first step to the study, Guidehouse conducted a market and baseline characterization
which is the collection and analysis of information pertaining to the size and characteristics
of Intermountain’s customer population. Market characterization forms the basis for
scaling up energy efficiency potential from a measure level to utility-wide level. This
information is referred to as global inputs and includes the following: building stock, gas
sales, avoided costs, retail rate, inflation rate, discount rate and building stock demolition
rate.
Additional study indices help define the breadth and scope of the study. Intermountain
study indices included two climate zones in Intermountain’s territory, climate Zone 5 and
Zone 6, and two sectors, residential and commercial. Climate Zones are a national
designation to categorize climate types for purposes of such studies. Within each sector,
customer segments were identified. In the residential sector there were two segments,
single family, and multi-family. Nine customer segments were identified in the commercial
sector, education, food service, healthcare, lodging, manufacturing/industrial, office, other,
retail and a new segment called light/converted commercial. Based on feedback from
customers and Energy Services Representatives, Intermountain requested Guidehouse
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explore this segment of commercial customers who are on the commercial rate but have
smaller energy usage and utilize residential-sized equipment. An example would be a law
office or medical office that operates in a residential building that has been converted to a
commercial business.
For the measure characterization, which is the categorization of energy efficiency measures
applicable to Intermountain’s residential and commercial sectors, measures were
prioritized for inclusion based on likelihood to have high savings, current market
availability and cost-effectiveness. In total, Guidehouse characterized 31 measures for the
residential sector and 55 measures for the commercial sector. Guidehouse considered the
following in developing the final measure list: existing measures offered by Intermountain,
measures that are not currently offered but were analyzed in the previous CPA, input from
Intermountain staff on additional measures of interest and other measures commonly
offered in other jurisdictions or commonly included in potential studies. Measure
characterization also included defining replacement types. Types identified for
Intermountain were new construction, replace on burnout or normal replacement, and
retrofit, which could be either an equipment add-on or accelerated replacement.
Characterization also specified parameters for each technology to calculate potential, such
as: measure description, replacement type, applicability, unit basis, energy consumption and
savings, costs, measure density and saturation, measure lifetime and net-to-gross ratio.
To characterize key inputs such as unit basis, energy consumption and savings, and cost
inputs for each measure, Guidehouse utilized a range of Technical Reference Manuals
(TRMs). Guidehouse prioritized the TRMs used in Intermountain’s CPA based on the
following criteria:
• Climate zone – TRMs from states with similar IECC climate zones,
• Codes and Standards – TRMs that do not set appliance standards beyond Federal
code requirements to avoid differing baseline efficiency levels when compared to
Idaho,
• Data Format – TRMs with deemed savings values were prioritized over TRMs that
only contained engineering algorithms and equations. Deemed savings are agreed-
upon savings resulting from installation of specified measures, not requiring
customized analysis after-the-fact. The advantage of using deemed values is the
ability to incorporate technical measure parameters and variables that have been
vetted and approved by the regulatory bodies and experts who maintain TRMs. In
addition, leveraging publicly available sources increases transparency and creates less
reliance on assumptions of key measure parameters by Guidehouse.
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Additionally, basing savings in potential studies on previous realized program results is an
industry best practice. Guidehouse utilized the findings from Intermountain’s 2020 Impact
Evaluation, Verification and Measurement (EM&V) for the furnace measure to inform
measure assumptions and account for realized program results in the characterization of
measure savings.
Guidehouse also developed density and saturation inputs. Density represents the
prevalence of a particular measure among the building stock, or number of units per
building. Saturation represents the percentage of a specific measure that is efficient or not.
Where applicable, density and saturation assumption that were documented in the 2019
CPA were also referenced.

3.6.4 Energy Efficiency Potential
The primary objective of the CPA was to develop an estimate of the potential for natural
gas energy efficiency in Intermountain’s service territory over a twenty-year horizon.
Three categories of potential savings, technical, economic, and achievable energy savings,
depicted in Figure 32, were calculated by Guidehouse. 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 the energy efficiency
savings that could be expected in response to specific levels of program incentives and
assumptions about existing policies, market influences and barriers.
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Figure 32: Guidehouse Categories of Potential Savings
Guidehouse tested the reasonableness of the model results by comparing historic program
performance and incentive spending with the modeled forecast. The modeled program net
savings potential was compared to the 2019-2021 historic program savings values by sector
and end-use. In addition, due to the year-over-year variations in program achievements,
rather than calibrating the model to a single point estimate like savings achieved in 2020,
Guidehouse looked at the savings trend over the past three years of program achievements.
The model was then calibrated to match the overall historical data. Guidehouse adjusted
model parameters to ensure the forecast net potential was grounded against real-world
results. To align adoption rates with historic program savings, a payback adder was applied
to most measures. A positive adder slows down adoption rates, while a negative payback
adder speeds up the adoption rate. Since the modeled level of adoption overstated the
2019-2021 historic program performance, a payback adder was used to calibrate measures.
Payback analysis is a standard approach to energy efficiency adoption by customers. For
measures with no historical data, the model was calibrated so these measures would have
very little achievable potential compared to measures with historical data.
With the model aligned as closely as possible with historic actual program achievements,
different model inputs (or a tuning of “levers” such as awareness and adoption) were used
to create alternative scenarios to examine how future achievable potential may vary
depending on variables both within Intermountain’s influence and external to it.
Guidehouse modeled achievable potential for 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
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as Usual (BAU), Unconstrained Historical budget, Medium Incentive, and combined High
Incentive, High Adoption.
The BAU scenario is most closely aligned and calibrated with historic program activity
based on program accomplishments. Incentive levels are defined as 50% of measure
incremental cost, with the exception of residential furnaces which were set at 40% of
incremental cost. This was done to ensure the largest potential measure was cost effective
throughout the study period. This scenario assumes future program budgets are closely
correlated with historic EE spending.
The three additional scenarios explored were: increased customer adoption of energy
efficiency through increased program activity, achieved without constraining program
spending at historic levels; a scenario of increased customer awareness and willingness to
adopt energy efficiency technologies; and increased customer awareness and willingness to
adopt combined with increased incentives. Figure 33 provides a synopsis of each scenario.
The cumulative net achievable potential for each scenario is illustrated in Figure 34. As
budgets, customer awareness and willingness to adopt increase so, too, does net achievable
potential of each scenario.

Figure 33: Cumulative Net Achievable Potential Synopsis

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Figure 34 Cumulative Net Achievable Potential by Scenario

Guidehouse compared Intermountain’s historic accomplishments to the achievable
potential estimated in the past and current CPA, illustrated in Figure 35, The Low Scenario
of the previous study had similar incremental achievable potential to the BAU scenario of
this study. The 2019 CPA included the commercial sector savings potential, but
Intermountain did not launch a commercial program until April 2021.
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Figure 35 Natural Gas Historic Accomplishments Compared to Past and Current Study Achievable

Given the comparison of historical achievements to the past and current studies, using the
BAU scenario to inform the IRP would be the most conservative approach. Net achievable
potential, by sector, for the BAU scenario is illustrated in Figure 38.

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.
Usage data is useful in tracking and evaluating energy saving measures, new production
procedures and/or usage characteristics of new equipment. To deploy this tool,
Intermountain installs SCADA units 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.
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In order to provide our customers with access to this data, Intermountain has designed
and hosts a Large Volume website, which is pictured in Figure 36. 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 data. An example of a month’s worth of data is provided in
Figure 37. 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.
Figure 36: Large Volume Website Login
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Figure 37: 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.

Figure 38: Cumulative Net Achievable Potential by Sector

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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:
ACnominal = CC + TC + VDC

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 in the calculation of the avoided cost:
• The assumed forward-looking annual inflation rate is 2.0%. (Inflation was
updated to 3.15% 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
Key Points
• Avoided cost forecasting
serves as a primary input for
determining energy
efficiency targets.
• Intermountain’s avoided
costs include transportation
costs, commodity costs, and
variable distribution costs.
• The discount rate is derived
using Intermountain’s tax-
effected cost of capital.
• 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.

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3.8.3 Understanding Each Component
3.8.3.1 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 represent the 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.

3.8.3.2 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’s inflation rate of 3.15%. (2% is typically used). 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.

3.8.3.3 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 this cost-benefit ratio may be intuitively
apparent, the Company and its Stakeholder group quantify these savings. Currently,
Intermountain included distribution system costs in the avoided cost as a scenario and
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ran the energy efficiency model to produce demand side savings based on a higher
avoided cost. The result did not remove or delay any of the distribution system
projects. Therefore, the Company is using a placeholder value of zero for this
component.

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4 Optimization

4.1 Distribution System Overview
Intermountain strives to provide safe and reliable
service to its customers. As part of Intermountain’s
distribution planning process Intermountain reviews its
systems for predicted growth and will identify and
address capacity deficits. If a capacity deficit is
identified reinforcement alternatives are compared and
final reinforcement is selected and budgeted within
Intermountain’s five year budget with consideration to
cost, system benefits and long-term planning.

This section will cover how Intermountain models its
distribution systems, identifies deficits, proposes
reinforcement alternatives to address deficits, reviews
and selects reinforcement alternatives and how projects
are put into the capital budget.

4.1.1 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 7,155 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 begin at a city gate station connected to
an interstate pipeline. At gate stations Intermountain takes custody of the gas and regulates
and odorizes the gas to serve its distribution and transmission pipelines. Typically, high
pressure or transmission pipelines are downstream of the gate to transport gas to regulator
stations or large volume industrial customers. Regulator station reduce pressure to serve
residential or commercial customers.

Key Points
• Distribution system network design fundamentals anticipate demand requirements and identify potential constraints.

• Cascade utilizes its internal
GIS environment and other input data to create system models through the use of
Synergi® software.
• Distribution system
enhancements include analyses of pipelines, regulators, and compressor stations.
• Impacts of proposed conservation resources on anticipated distribution constraints are reviewed.

• Analyses are performed on
every system at design day conditions to identify areas where potential outages
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4.1.2 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 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 maximum flow velocities at
which the gas is allowed to travel through the pipeline and related equipment.

Due to the nature of fluid mechanics, there is a finite amount of natural gas that can flow
through a pipe of a certain size 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.

In order 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. 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 anticipated future customer growth.
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4.2 Modeling Methodology
Intermountain utilizes a hydraulic gas network modeling and analysis software program
called Synergi Gas, distributed and supported by DNV GL, 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 and compressor stations and distribution
system networks and large diameter service connections.

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 five 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.
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 completely rebuilt every three years and are maintained
between rebuilds. To rebuild the models, Intermountain exports current GIS data to create
the spatial models and exports historical billing data from Customer Care and Billing
(CC&B) to bring into the Customer Management Module (CMM) to create an updated
demands file. Intermountain’s models were rebuilt in 2020 and are scheduled for rebuild
in 2023.
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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 CMM software product, provided by DNV GL 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 customer. The weather 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 weather information has been correlated to each meter read, a base load
and weather 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 GL.

The Company recognizes there could be significant differences in the way its customers
use natural gas throughout its geographically and economically diverse service territory.
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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 its 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 with the goal of installing fixed
network coverage on 90% of its system. Currently Intermountain’ s fixed network system
covers 61% of ERT meters and the fixed network installation is expected to be completed
by the end of 2023.

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 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 time and day and will then set the model to the
temperature experienced to see how the model is performing to determine if the usage per
custom is reasonable. 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 us to validate the model and have confidence that the usage per
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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 weather data, to create a design day model. Intermountain’s peak heating degree
days by district are shown in Figure 39.

District HDD Avg Daily Temperature (⁰F)
Figure 39: Peak Heating Degree Day

As shown in Figure 2, 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
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 sizing of
pipe and facilities, long term planning, model growth predictions, identify system deficits,
determine system reliability, optimize enhancement options and support cold weather
action plans.

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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 bottleneck, 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 its
distribution system models every two years to ensure that the Company can maintain
reliable service to our customers during design day events. Intermountain also completes
annual reviews of its distribution system models as part of its annual budgeting process
and will update the five-year budget as needed based upon new information that impacts
Intermountain’s five-year planning. If a deficit is predicted the system is evaluated and a
reinforcement will be proposed and selected based on alternative analysis criteria. 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, and district management to assure the system is safe and
reliable. As towns develop, the need for pipeline expansions and reinforcements increases.
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.

4.2.6 Distribution System Enhancements
Once a deficit has been identified on a system Engineering will propose enhancement
solutions to address the deficit. Distribution enhancements can include:

• pipeline reinforcement such as replacements
• pipeline loops and back feeds
• pressure increases
• uprates
• facility upgrades
• additional regulator station feeds
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• compressor stations
• demand side management strategies

Each of Intermountain’s systems are unique in pipeline dynamics and will be optimized
using different enhancement solutions.

Pipeline solutions consist of looping, upsizing, and uprating. 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 loss down the pipeline 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 upsizing involves replacing existing pipe with a larger size pipe. The increased
pipe capacity relative to surface area results in less friction, larger flow capacity, and
therefore, a lower pressure drop. This option is considered for older vintage pipelines. If
the existing pipe is otherwise in satisfactory condition, looping augments existing pipe,
which remains in use.

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 and or may not reach the
proposed uprate pressure. A thorough facility review is conducted to ensure pipeline
integrity before an uprate is conducted.

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
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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 city gate stations, district regulator stations, farm taps, and customer
services. Regulator station provide additional capacity to an area since regulator stations
are fed by high pressure laterals than can deliver more gas to the distribution system.
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 a significant deterrent. 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 alternative selection
process with consideration to scope, cost, timing, system benefits/long term planning and
feasibility. For any project over one 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 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.

• The shortest segment(s) of pipe that addresses the deficit.
• The segment of pipe with the most favorable construction conditions that supports
long term operations and maintenance activities, i.e., access, existing easements or
traffic issues.
• Minimizes environmental concerns, i.e., avoid water crossings, wetlands and
environmental sensitive areas.
• Minimizes impacts to the community., i.e., road closures or city road moratoriums.
• The segment of pipe that provides opportunity to add additional customers.
• Total construction costs including restoration.

Once a project/reinforcement is identified, engineering, field operations, or energy services
representatives begin a more thorough investigation by surveying the route and filing for
permits. This process may uncover additional impacts such as moratoriums on road
excavation, underground hazards, discontent among landowners, permitting concerns, etc.,
resulting in another iteration of the above project/reinforcement selection criteria.

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 timings needs with the goal of minimizing risk to ensure that we can continue to
provide safe and reliable service to our customers. Figure 40 provides a schematic
representation of the distribution system selection process to the capital budget.
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Figure 40: 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 assure projects are properly justified and necessary. Every year as part of
the capital budget process Intermountain projects are re-reviewed and revisions made to
the projects as needed as new information becomes available as part of Intermountain’s
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 time for projects to be designed and
constructed to address deficits in time. 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.

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4.3 Capacity Enhancements

4.3.1 Overview
Previous sections of this IRP show projected growth
throughout Intermountain gas’s 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 five-year budget based on when the
capacity enhancement needs to occur to avoid capacity
deficiencies.
The five identified Areas of Interest (AOI) 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 AOI the following items are summarized
below by AOI:
 AOI Summary/System Dynamics
 Capacity Limiter
 Capacity Enhancement Alternatives Considered
o Details/Scope
o Benefits o Additional Considerations o Cost
 Direct Cost
 Net Present Value Cost17

17 Included with this filing is a spreadsheet (in Exhibit 6) showing Intermountain’s net present value cost evaluation. To determine net present cost, IGC pulled various O&M cost for the alternatives proposed based
Key Points
• Capacity Enhancement
chapter provides an
evaluation of distribution
system projects by each Area
of Interest.
• Each evaluation provides
capacity enhancement
options, timing, cost, and the
final capacity option chosen.
• Ada County, Canyon County,
and Sun Valley Lateral are
showing immediate needs for
capacity upgrades. Idaho
Falls and State Street Laterals
are showing needs for
capacity upgrades in 2024
and 2025, respectively.

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o Capacity
 Table Summary of Capacity Enhancement Alternatives Considered
 Capacity Enhancement Selected o Reasoning o Timing
 2021 IRP Updates (as applicable)
At the end of the AOI summaries, a summary is included with Intermountain Gas’s five-year planning and timing of all the capacity enhancement selected and corresponding
capacity increases for the AOIs.

4.3.2 Canyon County
AOI 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 and 2021 with the 12-inch Ustick Phase I and
Phase II 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 significant growth in Nampa and surrounding communities this AOI requires a
capacity enhancement by 2023 to meet IRP growth. This AOI’s capacity is currently
limited by 8-inch and 10-inch HP on Ustick Road which is experiencing high flow rates
and causing high pressure to drop in this section and is compromising pressures down the
line which impacts the line’s capacity. The 8-inch and 10-inch HP is creating a bottleneck
in the system, which is limiting its capacity, the bottleneck is shown below in Figure 41 in
yellow.

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. O&M costs were inflated 2% each year over the 20-year life of the analysis and a real discount rate of 4.68% was used in the analysis based on the Company’s avoided cost model presented in Exhibit 5.
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Figure 41: Canyon County Limiter

Capacity Enhancement Alternatives Considered
Three alternatives were considered in the 2021 IRP. These alternatives include Ustick
Phase III, Ustick Uprate and an 8-inch High Pressure Extension north of Ustick. Ustick
Phase III was chosen in 2021 as the largest capacity increasing alternative.

Capacity Enhancement Selected
Ustick Phase III consists of installing 4.1 miles of HP Steel on Ustick Road with 4
regulators stations to reduce pressure from 500 psig to 330 psig as shown in Figure 42.

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Figure 42: Ustick Phase III

This enhancement brings the lateral capacity to 1,390,000 therms per day which meets the
predicted growth through 2028. Ustick Phase III construction has been delayed due to
conflicting city/county projects in the area and is expected to start this fall and is estimated
to cost $12,800,000 direct and $12,057,698 in net present value cost.

2021 IRP Updates
8-inch Happy Valley Extension- No longer required for this IRP since we are doing Ustick
Phase III instead, this could be a future IRP project.
12-inch Ustick Phase II- Was completed in 2021.

4.3.3 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.
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Capacity Limiter
Due to significant growth in Boise and north of Boise this AOI requires a capacity
enhancement by 2023 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.

Figure 43: State Street Capacity Limiter

Capacity Enhancement Alternatives
Two alternatives were considered in the 2021 IRP. These alternatives include 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.

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Figure 44: State Street Phase II Update

This enhancement brings lateral capacity to 950,000 therms per day which will meet
predicted growth through 2028. The State Street Phase II Uprate is budgeted for 2024 and
is estimated to cost $902,000 direct and $800,964 in net present value cost. The State Street
lateral also requires the State Penn Gate to be upgraded. No alternative analysis was
considered since the physical capacity of the gate is limiting capacity and needs to be rebuilt
in place with larger piping and components. The State Penn gate upgrade is budgeted for
2025 design and 2026 construction and is estimated to cost $2,730,000 direct. Net present
value cost is not applicable for gate upgrades since the upgraded gate has the same
operations and maintenance costs as the current gate.
4.3.4 Central Ada County
AOI Summary/System Dynamics
The Central Ada County AOI 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
that 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
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increased capacity in the area, the two systems are operating at different pressures and are
currently disconnected through system valving.
Capacity Limiter
Due to significant growth in Boise the Central Ada County AOI requires a capacity
enhancement by 2023 to meet IRP growth. The current capacity limiter for this AOI is a
10-inch and 8-inch HP bottleneck on Meridian Road and Victory Road directly
downstream of the Meridian Gate as shown in yellow in Figure 45.

Figure 45: Central Ada County Capacity Limiter

Capacity Enhancement Alternatives
Three alternatives were considered in the 2021 IRP. These alternatives include the 12-inch
South Boise Loop, uprating the 10-inch HP on Meridian Road and Victory Road or
installing a compressor station. The 12-inch South Boise Loop was chosen in 2021 as the
lowest cost option with the most capacity gained.
Capacity Enhancement Selected
The 12-inch South Boise Loop enhancement consists of installing 3.73 miles of 12-inch
HP Steel, a Kuna gate upgrade and a regulator station on Cloverdale Road near Victory
Road as shown in Figure 46.

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Figure 46: 12-inch South Boise Loop

This enhancement brings the lateral capacity to 870,000 therms per day which meets
predicted growth through 2028. The 12-inch Cloverdale project is completed. The Kuna
Gate is installed and is waiting on some regulator station parts to come in. The Victory and
Cloverdale regulator is in fabrication and will be installed this fall. This project will be online
this fall and is estimated to cost $17,900,000 direct and $17,254,430 in net present value
cost.

4.3.5 Sun Valley Lateral
AOI Summary/System Dynamics
The Sun Valley Lateral (SVL) is a 68-mile-long, 8-inch high pressure pipeline that has most
of its entire demand at the 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. Throughout the years Intermountain has uprated and upgraded this existing
lateral, and most recently installed the Jerome Compressor Station towards the south end
of the lateral to maintain capacity and increase flow toward the north end of the system.

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Capacity Limiter
Due to growth in Sun Valley this AOI requires a capacity enhancement by 2023 to meet
IRP growth. The current capacity limiter for this AOI is the end of line pressure on the
lateral to the Ketchum area as shown in yellow in Figure 47.

Figure 47: Sun Valley Lateral Capacity Limiter

Capacity Enhancement Alternatives
The Shoshone compressor station was selected in the 2019 IRP. Since 2019, the IGC
IRP has been improved and expanded. Alternative analysis discussion in the capacity
enhancement section started in the 2021 IRP filing.
Capacity Enhancement Selected
The Shoshone Compressor enhancement consists of installing a compressor station near
Shoshone, ID (Mile Post 32) on the Sun Valley lateral as shown in Figure 48.
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Figure 48: Shoshone Compressor Station

This enhancement brings lateral capacity to 247,500 therms per day which will meet predicted growth through 2028. The compressor is installed onsite and will be
commissioned this September to allow the compressor to be online for winter demand.
The compressor station is estimated to cost at $6,700,000 direct and $8,769,994 in net
present value costs.

4.3.6 Idaho Falls Lateral
AOI 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
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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
Due to growth in Idaho Falls this AOI requires a capacity enhancement by 2024 to meet
IRP growth. 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 49.

Figure 49: Idaho Falls Lateral Capacity Limiter

Capacity Enhancement Alternatives
Two alternatives were considered in the 2021 IRP. Those alternatives included a Blackfoot
Compressor Station or a Phase IV Pipeline with an additional LNG Tank in Rexburg. The
Blackfoot Compressor station was chosen in the 2021 IRP as the lowest cost option that
provided the largest capacity to the lateral.

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Capacity Enhancement Selected
The Blackfoot Compressor enhancement consists of installing a compressor station near
Blackfoot, ID on the Idaho Falls lateral as shown in Figure 50.

This enhancement brings lateral capacity to 1,093,000 therms per day (assumes Rexburg
LNG is offline) which would meet predicted growth through 2028. The compressor has
been ordered with land acquisition and required permit applications ongoing. Construction
is planned to commence in 2024 with costs estimated at $20,000,000 in direct and
$22,822,278 in net present value cost.

With the decision of adding the Blackfoot compressor station, Intermountain will need to
keep the Rexburg satellite LNG facility as a peak shaving facility until 2024 when the
Blackfoot compressor station comes online. After 2024, Intermountain plans to keep the
Rexburg satellite LNG facility as an emergency backup to provide additional system
reliability to the Idaho Falls lateral.
Other AOI
Figure 50: Idaho Falls Lateral Blackfoot Compressor
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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, the Payette Gate Upgrade
and the New Plymouth Gate Upgrade.
Capacity Limiter
Once a gate approaches its 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.
Capacity Enhancement Alternatives
No alternatives to consider for gate upgrades in the small towns of Payette and 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.
Capacity Enhancement Selected
The Payette Gate upgrade and New Plymouth Gate upgrade both need to be completed
by 2024 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 Payette Gate Upgrade is estimated to cost $3,490,000
in direct costs and the New Plymouth Gate Upgrade is estimated to cost $2,760,000 in
direct costs. Net present value cost is not applicable for gate upgrades since the upgraded
gate has the same operations and maintenance costs as the current gate.

4.3.7 Summary
To summarize the AOI capacity enhancements, below in Table 10 is a capacity summary
showing the capacity enhancement selected from IGC’s alternative analysis and
corresponding capacity increases.

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Table 10: Five-Year Planning and Timing of Capacity Enhancements Selected
AOI → Ada County State Street Lateral Canyon County Sun Valley Lateral Idaho Falls Lateral
Year↓ Capacity (th/day) Enhancement Capacity (th/day) Enhancement Capacity (th/day) Enhancement Capacity (th/day) Enhancement Capacity (th/day) Enhancement
2023 870,000 12-inch S Boise Loop Ustick Compressor
Compressor
Gate

As is shown in Table 10, five years is sufficient time to identify, budget, plan, design and
construct projects to address capacity deficits. As part of the IRP process, IGC will check
its five-year plan deficits and alternatives considered for capacity enhancement in the next
IRP filling in 2025 and adjust the Company’s plan as needed to ensure reliable service to
Intermountain’s customers based on the next round of IRP growth predictions. This will
be an ongoing iterative process as part of IGC’s two-year IRP filing.

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4.4 Load Demand Curves
The culmination of the demand forecasting process is
aggregating the information discussed in the previous
sections into a forecast of future load requirements. As the
previous sections illustrate, the customer forecast, design
weather, core market usage per customer data, large volume
usage forecast, and demand side management are all key
drivers in the development of the Load Demand Curves
(LDC).
The IRP customer forecast provides a total Company daily
projection through Planning Year (PY) 2028 and includes a
forecast for each of the five AOIs of the distribution system.
Each forecast was developed under each of three different
customer growth scenarios: low growth, base case, and high
growth.
The development of a design weather curve – which reflects
the coldest anticipated weather patterns across the
Company’s service area – provides a means to distribute the
core market’s heat sensitive portion of Intermountain’s load
on a daily basis. Applying design weather to the residential
and small commercial usage per customer forecast creates
core market usage per customer under design weather
conditions. That combined with the applicable customer
forecast yields a daily core market load projection through
PY28 for the entire company, as well as for each AOI. Similar
to the above, normal weather scenario modeling was also completed.
As discussed in the Large Volume Customer Forecast Section, the forecast also
incorporates the large volume Contract Demand from both a Company-wide perspective
(interstate capacity) as well as from an AOI perspective (distribution capacity). When added
to the core market figures, the result is a grand total daily forecast for both gas supply and
capacity requirements including a break-out by AOI.
Peak day send-out under each of these customer growth scenarios was measured against
the currently available capacity to project the magnitude, frequency and timing of potential
delivery deficits, both from a Company perspective and an AOI perspective.
Key Points
• Load Demand Curves
(LDC) calculates
Intermountain’s projected
usage during the planning
horizon.
• Intermountain does a base,
high, and low LDC for each
area of interest and for the
total company.
• Intermountain expects the
Company to increase by
increase of 69,894
customers, or 2.8% per
year, over the planning
horizon.
• Under expected customer
growth and normal weather,
Intermountain expects
usage to grow to 50 million
therms by 2028.
• Due to this growth,
Intermountain anticipates
distribution system shortfalls
at each area of interest,
requiring distribution system
upgrades.
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Once the demand forecasts were finished and the evaluation complete, the data was input
into SENDOUT®, the Company’s optimization model, for IRP modeling. The LDC
incorporates all the factors that will impact Intermountain’s future loads. The LDC is the
basic tool used to reflect demand in the IRP Optimization Model.
It is important to note that the Load Demand Curves, found in Exhibit 7, represent existing
resources and are intended to identify potential capacity constraints and to assist in the long-
term planning process. Plans to address any identified deficits will be discussed in the
Planning Results Section of this report.

4.4.1 Customer Growth Summary Observations – Design Weather – All Scenarios
Idaho Falls Lateral
The Idaho Falls Lateral low growth scenario projects an increase in customers of 6,542
PY23 through PY28 (Jan 1, 2023 to Dec 31, 2028) which corresponds to an annualized
growth rate of 1.72%. In the base case scenario customers are forecasted to increase by
10,786 (2.75% annualized growth rate), while the high growth scenario forecasts an
increase of 14,473 customers (3.62% annualized growth rate).
Sun Valley Lateral
The Sun Valley Lateral low growth scenario (PY23 – PY28) projects an increase of 705
customers (0.89% annualized growth rate). In the base case scenario customers are
projected to increase by 1,142 (1.43% annualized growth rate), while the high growth
scenario shows an increase of 1,607 customers (1.98% annualized growth rate).
Canyon County Area
The low growth customer forecast (PY23 – PY28) for Canyon County Area reflects an
increase of 13,221 customers (3.28% annualized growth rate). In the base case scenario
customers are forecasted to increase by 16,011 (3.92% annualized growth rate), while the
high growth scenario projects an increase of 19,414 customers (4.66% annualized growth
rate).
State Street Lateral
The low growth customer forecast (PY23 – PY28) for the State Street Lateral reflects an
increase of 7,175 customers (1.92% annualized growth rate). The base case scenario
projects an increase of 8,980 customers (2.38% annualized growth rate), while the high
growth scenario forecasts an increase of 10,640 customers (2.79% annualized growth rate).
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Central Ada County
The low growth customer forecast (PY23 – PY28) for the Central Ada County reflects an
increase of 7,281 customers (1.95% annualized growth rate). In the base case scenario
customers are forecasted to increase by 9,048 (2.40% annualized growth rate), while the
high growth scenario projects an increase of 10,671 customers (2.80% annualized growth
rate).
Total Company
The Total Company (TC) low growth customer forecast (PY23 – PY28) projects an
increase of 46,805 customers (1.84% annualized growth rate). The base case scenario
forecasts an increase of 66,100 customers (2.56% annualized growth rate), while the high
growth scenario projects an increase of 84,546 customers (3.22% annualized growth rate).
Please note that the TC forecasts include the AOIs mentioned above as well as all other
customers not located in a particular AOI.
Using the LDC analyses allows Intermountain to anticipate changes in future demand
requirements and plan for the use of existing resources and the timely acquisition of
additional resources.

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4.4.2 Core Customer Distribution Sendout Summary – Design and Normal Weather – All
Scenarios
Idaho Falls Area

Table 11: Idaho Falls Lateral Design Weather – Annual Core + LV-1 Market Distribution Sendout (Dth)
Scenario 2023 2024 2025 2026 2027 2028
8,109,610 8,136,524 8,188,219 8,297,228 8,400,679 8,531,564
Base 8,181,825 8,402,905 8,538,387 8,711,484 8,881,916 9,095,710
High

Table 12: Idaho Falls Normal Weather - Annual Core + LV-1 Market Distribution Sendout (Dth)
Scenario 2023 2024 2025 2026 2027 2028
7,105,271 7,123,585 7,168,588 7,259,255 7,345,857 7,450,820
7,169,715 7,355,295 7,472,846 7,619,274 7,762,969 7,940,232
7,220,835 7,573,359 7,787,819 7,992,798 8,164,839 8,376,848

Sun Valley Area

Table 13: Sun Valley Design Weather - Annual Core + LV-1 Market Distribution Sendout (Dth)
Scenario 2023 2024 2025 2026 2027 2028
2,339,468 2,356,144 2,358,636 2,377,920 2,400,107 2,427,796
2,350,870 2,392,856 2,409,577 2,436,944 2,463,497 2,502,063
2,360,063 2,430,295 2,458,404 2,504,628 2,538,271 2,584,974
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Sun Valley Area (cont.)

Table 14: Sun Valley Normal Weather - Annual Core + LV-1 Market Distribution Sendout (Dth)
Scenario 2023 2024 2025 2026 2027 2028
1,989,354 2,001,835 2,004,423 2,019,854 2,037,659 2,058,973
1,999,014 2,032,984 2,047,585 2,069,943 2,091,440 2,121,814
2,006,607 2,064,524 2,088,846 2,127,168 2,154,794 2,192,114

Canyon County Area

Table 15: Canyon County Design Weather - Annual Core + LV-1 Market Distribution Sendout (Dth)
Scenario 2023 2024 2025 2026 2027 2028
8,587,798 8,740,367 8,881,047 9,174,525 9,409,297 9,741,969
8,650,142 8,967,484 9,205,257 9,547,643 9,830,009 10,168,730
8,694,642 9,184,905 9,508,604 9,932,948 10,280,995 10,700,503

Table 16: Canyon County Normal Weather - Annual Core + LV-1 Market Distribution Sendout (Dth)
Scenario 2023 2024 2025 2026 2027 2028
6,778,360 6,887,336 6,990,835 7,224,280 7,400,912 7,654,100
6,828,816 7,066,567 7,245,086 7,518,174 7,731,250 7,989,193
6,863,981 7,237,655 7,483,465 7,820,823 8,085,852 8,408,690

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State Street Lateral

Table 17: State Street Design Weather - Annual Core + LV-1 Market Distribution Sendout (Dth)
Scenario 2023 2024 2025 2026 2027 2028
7,962,950 8,006,760 8,041,609 8,140,414 8,265,408 8,379,593
8,011,559 8,182,741 8,279,803 8,414,827 8,550,398 8,727,951
8,047,006 8,338,892 8,497,203 8,699,947 8,837,401 9,041,741

Table 18: State Street Normal Weather - Annual Core + LV-1 Market Distribution Sendout (Dth)
Scenario 2023 2024 2025 2026 2027 2028
6,201,390 6,224,348 6,244,440 6,311,800 6,401,176 6,480,463
6,240,172 6,363,348 6,431,634 6,528,324 6,625,572 6,754,413
6,268,456 6,486,020 6,602,340 6,752,408 6,851,519 7,001,523

Central Ada County

Table 19: Central Ada Design Weather - Annual Core + LV-1 Market Distribution Sendout (Dth)
Scenario 2023 2024 2025 2026 2027 2028
7,918,054 7,970,001 8,008,307 8,108,882 8,231,921 8,347,829
7,962,390 8,130,951 8,226,587 8,359,609 8,493,183 8,668,143
7,994,970 8,274,665 8,427,177 8,622,055 8,757,408 8,957,541

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Central Ada County (cont.)

Table 20: Central Ada Normal Weather - Annual Core + LV-1 Market Distribution Sendout (Dth)
(Dth)
Scenario 2023 2024 2025 2026 2027 2028
6,206,215 6,235,675 6,258,153 6,326,867 6,414,542 6,495,230
6,241,521 6,362,628 6,429,498 6,524,465 6,619,996 6,746,799
6,267,453 6,475,382 6,586,766 6,730,450 6,827,733 6,974,402

Total Company
Table 21: Total Company Design Weather - Annual Core + LV-1 Market Distribution Sendout (Dth)
Scenario 2023 2024 2025 2026 2027 2028
55,917,129 56,240,941 56,502,397 57,281,905 58,129,130 59,107,231
56,313,064 57,667,418 58,452,537 59,591,309 60,671,553 62,056,494
56,617,857 59,011,480 60,349,924 61,950,883 63,244,041 64,949,121

Table 22: Total Company Normal Weather - Annual Core + LV-1 Market Distribution Sendout (Dth)
Scenario 2023 2024 2025 2026 2027 2028
45,707,995 45,923,649 46,103,886 46,705,306 47,356,583 48,101,759
46,035,614 47,085,442 47,687,152 48,583,343 49,420,351 50,495,942
46,284,345 48,175,848 49,226,704 50,497,575 51,509,277 52,844,927

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4.4.3 Projected Capacity Deficits – Design Weather – All Scenarios
Residential, commercial, and industrial peak day load growth on Intermountain’s system is
forecast over the six-year period to grow at an average annual rate of 1.14% (low growth),
2.18% (base case) and 3.10% (high growth), highlighting the need for long-term planning.
The next section illustrates the projected capacity deficits by AOI during the IRP planning
horizon.
Idaho Falls Lateral LDC Study
When forecast peak day send-out on the Idaho Falls Lateral is matched against the existing
peak day distribution capacity (90,400), peak day delivery deficit occurs under the base case
scenario beginning in PY27.
Table 23: Idaho Falls Design Weather - Peak Day Deficit Under Existing Resources (Dth)
Scenario 2023 2024 2025 2026 2027 2028
0 0 0 0 0 0
0 0 0 0 1,211 2,830
0 0 950 3,136 5,112 7,057

Sun Valley Lateral LDC Study
When forecasted peak day send out on the Sun Valley Lateral is matched against the
existing peak day distribution capacity (20,000 Dth), peak day delivery deficits occur in
PY24 under the base case scenario.

Table 24: Sun Valley Design Weather - Peak Day Deficit Under Existing Resources (Dth)
Scenario 2023 2024 2025 2026 2027 2028
0 0 0 57 275 424
0 34 281 522 762 999
0 324 636 1,045 1,339 1,623

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Canyon County Area LDC Study
When forecasted peak day send out for the Canyon County Area is matched against the
existing peak day distribution capacity (103,200 Dth), peak day delivery deficits occur
beginning in PY24 under the base case scenario.

Table 25: Canyon County Design Weather - Peak Day Deficit Under Existing Resources (Dth)
Scenario 2023 2024 2025 2026 2027 2028
0 0 1,083 3,677 5,939 8,853
0 1,021 4,041 7,037 9,868 12,726
0 2,936 6,733 10,503 13,919 17,353

State Street Lateral LDC Study
When forecasted peak day send out for the State Street Lateral is matched against the
existing peak day distribution capacity (82,000 Dth), a peak day delivery deficit occurs in
PY28 under the base case scenario.

Table 26: State Street Design Weather - Peak Day Deficit Under Existing Resources (Dth)
Scenario 2023 2024 2025 2026 2027 2028
0 0 0 0 0 0
0 0 0 0 0 892
0 0 0 419 1,950 3,624

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Central Ada County LDC Study

Table 27: Central Ada Design Weather - Peak Day Deficit Under Existing Resources (Dth)
Scenario 2023 2024 2025 2026 2027 2028
0 0 0 729 2,124 3,090
0 0 1,484 2,978 4,474 5,973
0 1,248 3,260 5,334 6,846 8,499

When forecasted peak day send out for the Central Ada County is matched against the
existing peak day distribution capacity (74,500 Dth), peak day delivery deficits occur in
PY25 under the base case scenario.

Total Company LDC Study
The Total Company perspective differs from the laterals in that it reflects the amount of
gas that can be delivered to Intermountain via the various resources on the interstate
system. Hence, total system deliveries should provide at least the net sum demand – or the
total available distribution capacity where applicable - of all the laterals/AOIs on the
distribution system. The following table shows peak day deficits. The solution for this
shortfall is discussed further in the Upstream Modeling Results portion of the Planning
Results section.

Table 28: Total Company Design Weather - Peak Day SENDOUT (Core+LV-1) Deficit Under Existing Resources (Dth)
Resources (Dth)
Scenario 2023 2024 2025 2026 2027 2028
38,567 38,509 44,487 52,999 62,255 69,796
40,534 50,639 61,793 73,234 84,764 95,734
41,972 62,003 78,164 93,901 107,305 120,830
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4.4.4 2021 IRP vs. 2023 IRP Common Year Comparisons
This section compares the Total Company and each AOI during the three common years
of the 2023 and 2021 IRP filings. In some cases, the distribution transportation capacity
may be forecasting lower in the 2023 IRP than it was in the 2021 IRP. This is the result of
differences in, or fine tuning of, planned capacity upgrades.
Total Company Design Weather/ Base Case Growth Comparison

Table 29: 2023 IRP Load Demand Curve – TC Usage Design Base Case (Dth)

2023 IRP LOAD DEMAND CURVE – TC USAGE DESIGN BASE CASE (Dth)

Core

1

Total

2024 492,900 150,254 643,154
2025 504,275 150,474 654,749
2026 515,575 151,064 666,639
1Existing firm contract demand includes LV-1 and T-4 requirements.

Table 30: 2021 IRP Load Demand Curve – TC Usage Design Base Case (Dth)
2021 IRP LOAD DEMAND CURVE – TC USAGE DESIGN BASE CASE (Dth)

Core Firm CD1 Total

2024 498,202 140,364 638,566
2025 510,868 140,779 651,647
2026 522,487 141,379 663,866
1Existing firm contract demand includes LV-1 and T-4 requirements.

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Table 31: 2023 IRP Load Demand Curve – TC Usage Design Base Case

2023 IRP LOAD DEMAND CURVE – TC USAGE DESIGN BASE CASE
Over/(Under) 2021 IRP (Dth)

Core
Peak Day Sendout

Firm CD1

Total

2024 (5,303) 9,890 4,587
2025 (6,593) 9,695 3,102
2026 (6,912) 9,685 2,773
Existing firm contract demand includes LV-1 and T-4 requirements.

Total Company Peak Day Deliverability Comparison

Table 32: 2023 IRP Peak Day Firm Delivery Capability (Dth)
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
245,512 245,512 245,512
341,043 338,043 338,043

586,555 583,555 583,555

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Table 33: 2021 IRP Peak Day Firm Delivery Capability (Dth)
2021 IRP PEAK DAY FIRM DELIVERY CAPABILITY (Dth)
Maximum Daily Storage Withdrawals:
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
245,512 245,512 245,512
332,043 332,043 332,043
577,555 577,555 577,555

Table 34: 2023 IRP Peak Day Firm Delivery Capability

Over/(Under) 2021 (Dth)

Maximum Daily Storage Withdrawals:
Nampa LNG 0 0 0
Plymouth LS 0 0 0
Jackson Prairie SGS 0 0 0
0 0 0
9,000 6,000 6,000
9,000 6,000 6,000
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Idaho Falls Lateral Design Weather/Base Case Growth Comparison

Table 35: 2023 IRP Load Demand Curve – IFL Usage Design Base Case (Dth)

Distribution Core
Peak Day Sendout
Firm CD1 Total

2024 109,300 66,408 20,201 86,609
2025 109,300 68,122 20,301 88,423
2026 109,300 69,823 20,301 90,124

1Existing firm contract demand includes LV-1 and T-4 requirements.

Table 36: 2021 IRP Load Demand Curve – IFL Usage Design Base Case (Dth)

2021 IRP LOAD DEMAND CURVE – IFL USAGE DESIGN BASE CASE (Dth)

Distribution

Core

Peak Day Sendout

Firm CD1

Total

2024 109,300 68,029 21,331 89,360
2025 109,300 69,448 21,331 90,779
2026 109,300 70,825 21,381 92,206
1

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Table 37: 2023 IRP Load Demand Curve – IFL Usage Design Base Case Over/(Under) 2021 IRP (Dth)

2023 IRP LOAD DEMAND CURVE – IFL USAGE DESIGN BASE CASE
Over/(Under) 2021 IRP (Dth)

Distribution Transport

Core

Peak Day Sendout

Firm CD1

2024 0 (1,621) (1,130) (2,751)
2025 0 (1,326) (1,030) (2,356)
2026 0 (1,002) (1,080) (2,082)
1Existing firm contract demand includes LV-1 and T-4 requirements.

Sun Valley Lateral Design Weather/ Base Case Growth Comparison

Table 38: 2023 IRP Load Demand Curve – SVL Usage Design Base Case (Dth)
2023 IRP LOAD DEMAND CURVE – SVL USAGE DESIGN BASE CASE (Dth)

Distribution
Transport Core
Peak Day Sendout
Firm CD1
Total

2024 24,750 18,105 1,935 20,040
2025 24,750 18,361 1,935 20,296
2026 24,750 18,613 1,935 20,548
Existing firm contract demand includes LV-1 and T-4 requirements.
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Table 39: 2021 IRP Load Demand Curve –SVL Usage Design Base Case (Dth)
2021 IRP LOAD DEMAND CURVE –SVL USAGE DESIGN BASE CASE (Dth)

Distribution Core
___________________

Firm CD1
Total

2024 24,750 19,360 1,935 21,295
2025 24,750 19,634 1,935 21,569
2026 24,750 19,830 1,935 21,765

1Existing firm contract demand includes LV-1 and T-4 requirements.

Table 40: 2021 IRP Load Demand Curve –SVL Usage Design Base Case (Dth)

2023 IRP LOAD DEMAND CURVE –SVL USAGE DESIGN BASE CASE
Over/(Under) 2021 (Dth)

Distribution

Core
Peak Day Sendout
______________________

1

Total

2024 0 (1,255) 0 (1,255)
2025 0 (1,273) 0 (1,273)
2026 0 (1,217) 0 (1,217)
1
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Canyon County Area Design Weather/ Base Case Growth Comparison

Table 41: 2023 IRP Load Demand Curve – CCA Usage Design Base Case (Dth)
2023 IRP LOAD DEMAND CURVE – CCA USAGE DESIGN BASE CASE (Dth)

Distribution Core
Peak Day Sendout

1

Total

2024 139,000 79,570 24,740 104,310
2025 139,000 82,469 24,940 107,409
2026 139,000 85,370 25,110 110,480

1

Table 42: 2021 IRP Load Demand Curve – CCA Usage Design Base Case (Dth)

Distribution Core 1 Total

2024 139,000 78,588 24,790 103,378
2025 139,000 81,553 24,790 106,343
2026 139,000 83,917 24,790 108,707

1
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Table 43: 2023 IRP Load Demand Curve – CCA Usage Design Base Case Over/(Under) 2021 (Dth)
2023 IRP LOAD DEMAND CURVE – CCA USAGE DESIGN BASE CASE
Over/(Under) 2021 (Dth)

Distribution

Core

Peak Day Sendout

Firm CD1

Total

2024 0 982 (50) 932
2025 0 916 150 1,066
2026 0 1,453 320 1,773
1
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State Street Lateral Design Weather/ Base Case Growth Comparison

Table 44: 2023 IRP Load Demand Curve – SSL Usage Design Base Case (Dth)
2023 IRP LOAD DEMAND CURVE – SSL USAGE DESIGN BASE CASE (Dth)

Distribution Core Firm CD1
Total

2024 82,000 75,961 990 76,951
2025 95,000 77,563 990 78,553
2026 95,000 79,163 990 80,153

1Existing firm contract demand includes LV-1 and T-4 requirements.

Table 45: 2021 IRP Load Demand Curve – SSL Usage Design Base Case (Dth)
2021 IRP LOAD DEMAND CURVE – SSL USAGE DESIGN BASE CASE (Dth)

Distribution Core 1

2024 95,000 76,823 990 77,813
2025 95,000 79,183 990 80,173
2026 95,000 81,614 990 82,604

1
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Table 46: 2023 IRP Load Demand Curve – SSL Usage Design Base Case Over/(Under) 2021 (Dth)

2023 IRP LOAD DEMAND CURVE – SSL USAGE DESIGN BASE CASE
Over/(Under) 2021 (Dth)

Distribution

Core
_____________________

1

Total

2024 (13,000) (862) 0 (862)
2025 0 (1,620) 0 (1,620)
2026 0 (2,451) 0 (2,451)
1Existing firm contract demand includes LV-1 and T-4 requirements.
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Central Ada County Design Weather/ Base Case Growth Comparison

Table 47: 2023 IRP Load Demand Curve – CAC Usage Design Base Case (Dth)
2023 IRP LOAD DEMAND CURVE – CAC USAGE DESIGN BASE CASE (Dth)

Distribution Core Firm CD1
Total

2024 87,000 73,738 850 74,588
2025 87,000 75,327 850 76,177
2026 87,000 76,914 850 77,764

1

Table 48: 2021 IRP Load Demand Curve – CAC Usage Design Base Case (Dth)
2021 IRP LOAD DEMAND CURVE – CAC USAGE DESIGN BASE CASE (Dth)

Distribution Core 1 Total

2024 87,000 73,634 950 74,584
2025 87,000 74,812 950 75,762
2026 87,000 76,002 950 76,952

1
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Table 49: 2023 IRP Load Demand Curve – CAC Usage Design Base Case Over/(Under) 2021 (Dth)

2023 IRP LOAD DEMAND CURVE – CAC USAGE DESIGN BASE CASE
Over/(Under) 2021 (Dth)

Distribution

Core

Peak Day Sendout

Firm CD1

Total

2024 0 104 (100) 4
2025 0 515 (100) 415
2026 0 912 (100) 812
1Existing firm contract demand includes LV-1 and T-4 requirements.

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, 2023 to 2028.
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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 Areas of Interest (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 this 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 previous IRP was a computer optimization model
known as SENDOUT®. In this IRP, Intermountain is utilizing PLEXOS®, which is
a very similar model to SENDOUT®.

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
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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 51 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.

Figure 51: 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 51.
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4.5.5 Demand Area Forecasts
As previously discussed in the Load Demand Curves Section beginning on page Error!
Bookmark not defined., 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 Section on page 6. Intermountain
forecasts peak demand to be 481,535 dth for RS (Residential) and GS (commercial)
customers and 151,054 dth for LV-1 and T-4 customers in 2023 and growing to 538,255
dth and 151,774 dth in 2028, respectively.
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Figure 52: IGC Laterals from Zone 24
The demand areas listed in Figure 52 are:
• Central Ada Area
• State Street Lateral
• Canyon County Region
• Idaho Falls Lateral
• Sun Valley Lateral
• All Other

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Figure 53: Total Company Design Base 2023
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 53 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 for the 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.
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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 54 shows the supply area (in green) providing gas at the Opal
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.

Figure 54: IGC Supply Model Example

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Figure 55: IGC Storage Model Example

Figure 55 shows an example of the SENDOUT 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. Figure 56 shows the DSM applied directly to the AOI. 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 (starting on page
Error! Bookmark not defined.).

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Figure 56: IGC DSM Model Example

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 our
transportation model is seen in Figure 57.
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Figure 57: 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.
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-à-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
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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 for a 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; 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
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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 being the 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. Table 50 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.

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Table 50: 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 2023 through 2028 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. Table 51 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
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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
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).

Table 51: Lateral Summary by Year

Table 52 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.

Table 52: Annual Traditional Supply Resources Results

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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.
A sample of the Annual Transportation Resources Results from Exhibit 8 for the
Design Base scenario is displayed Table 53. Exhibit 8 also provides transportation
results by month for the planning horizon.

Table 53: 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
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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 seasons. An analysis on lateral expansion is performed
as well as an analysis to check for any shortfalls in upstream transportation or supply
capacity.

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 2023 and
2021 IRP filings. Finally, the planning results for upstream transportation shortfalls are
discussed.

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4.6.2 Distribution System Planning
Canyon County
In the Capacity Enhancements section, four options are discussed to determine the best
way to solve capacity shortfalls for the Canyon County AOI. The option chosen was
the Ustick Phase III enhancements.
The following graph (Figure 58) shows no deficit in the final year of the planning
horizon under the base case scenario after completion of the proposed capacity
upgrades.

Figure 58: LDC Design Base Case – Canyon County Lateral

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 (Figure 59) shows no deficit in the final year of the planning
horizon under the base case scenario after completion of the proposed capacity
upgrade.
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Figure 59: LDC Design Base Case – State Street Lateral

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Central Ada County
In the Capacity Enhancements section, three options are discussed to determine the
best way to solve capacity shortfalls for the Central Ada County AOI. The option
chosen was the 12-inch South Boise Loop upgrade.
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.

Figure 60: LDC Design Base Case – Central Ada Lateral

Sun Valley Lateral
In the Capacity Enhancements section, one option was identified in the 2019 IRP as
the best way to solve capacity shortfalls for the Sun Valley Lateral: Shoshone
Compressor Station. The Shoshone compressor station was planned to be installed by
the end of 2021 but due to land acquisition delays will not be completed until summer
of 2022. To address potential shortfalls during a cold weather event on the Sun Valley
Lateral until the Shoshone compressor station comes online, Intermountain has
developed a plan for the 2021-2022 winter. The plan for this lateral consists of
communicating with downstream customers to turn off their snow melt equipment,
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running the Jerome compressor station ahead of a severe weather event to pack the
lateral, bypassing critical regulator stations as needed to maintain service and to keep
pressure on the lateral as high as possible and communicating with large volume
customers to adhere to their contract demands during the cold weather event. Because
the identified deficit is relatively small, Intermountain believes these measures will keep
customers adequately supplied should a cold weather event occur.
The following graph (Figure 62) shows no deficit in the final year of the planning
horizon under the base case scenario after completion of the proposed capacity
upgrade.

Figure 61: LDC Design Base Case – Sun Valley Lateral

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Idaho Falls Lateral
In the Capacity Enhancements section, two options are discussed to determine the best way to solve capacity shortfalls for the Idaho Falls Lateral. The option chosen was the
Idaho Falls Lateral Compressor Station.
The following graph (Figure 63) shows no deficit in the final year of the planning
horizon under the base case scenario after completion of the proposed capacity upgrade.

Figure 62: LDC Design Base Case – Idaho Falls Lateral

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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 indicated in Table 9 on page
64, total citygate delivery declines beginning in 2023 as upstream transportation
contracts begin to expire. Also, due to the segmentation of Sumas capacity,
Intermountain has a shortage of capacity getting gas to Stanfield. Due to expiring
contracts and the need for more capacity to GTN, Intermountain does show a shortfall
in the final year of the planning horizon, where Intermountain anticipate will be served
through incremental transport. The following graph (Figure 64) shows the shortfall
created by expiring contracts (blue line).

Figure 63: 2028 Design Base Case – Total Company

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Solving Upstream Resources Shortfall
The options to solve the current transportation shortfall are contract renewal, alternative
transportation uptake, and RNG. Under the contract renewal option, the contracts that
will expire will be evergreened, or auto renewed, which provides Intermountain with
sufficient transportation to meet load. Under the alternative transportation uptake, the
model has the option to choose an alternative transportation rather than renewing. An
example of this would be picking up more GTN rather than renewing a contract that
moves gas from Sumas to Stanfield. In the RNG option, Intermountain models
potentially decreasing the need of upstream transportation by giving the resource
optimization model the option to take RNG.
The results in Exhibit 8 show that the options chosen to solve the shortfall are contract
renewal and alternative transportation uptake. Currently, due to the high price of RNG,
it was not selected to meet the shortfall solve as it would not have been the least-cost
option. The resource optimization model has chosen to renew several of the expiring
contracts while also choosing incremental GTN, which Intermountain will solve with
GTN Xpress. With that said, the model also indicates that Intermountain must add
20,000 to 30,000 dth/day of incremental transportation in the final year of the planning
horizon.
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. Figure 65 shows the final
year of the planning horizon along with the Company’s solutions to meet upstream
shortfalls.
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Figure 64: 2028 Design Base Case Shortfall Solution – Total Company

4.6.4 Conclusion
The distribution system planning results showed that the Company needs 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 expiring transportation contracts. That shortfall will be solved by taking
either renewed or alternative transportation contracts, with the ultimate decision coming
from Intermountain’s GSOC.
4.7 Non-Utility LNG Forecast

4.7.1 Introduction
Since 1974, Intermountain has operated its Nampa Liquid Natural Gas (LNG) facility
as a winter peaking supply source. The plant is designed to liquefy natural gas into LNG,
store it in an onsite tank and vaporize it for injection into the Company’s distribution
system. The plant design includes a 50,000 gallon per day liquefaction train, a seven
million-gallon storage tank and two water-bath vaporization units. The Nampa facility
is utilized as the top of the Company’s supply stack, or in other words, the last supply
source that is used in the event of very cold weather or extraordinary system constraints.
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In 2012 Intermountain began an efficiency review that focused on how it might better
utilize its Nampa asset. Utilizing the then current IRP forecast, Intermountain
determined how many gallons were projected to be withdrawn each winter season. That
analysis showed that even under design weather assumptions, an excess of LNG supply
would likely be available in each winter season.
Concurrent with the efficiency study, Intermountain began a study to determine the
status of the regional LNG supply market relative to providing LNG to the Company’s
remote LNG facility near Rexburg, Idaho. Intermountain contacted several producing
and marketing entities in the area who were then engaged in the non-utility LNG
business to gauge future supply as well as the potential to enter the market as a supplier
of LNG. It was discovered that due to already existing firm commitment during the
heating season, it would be difficult to guarantee that an LNG supply would be available
to Intermountain’s Rexburg facility during the peak winter months.

4.7.2 History
LNG is a clean burning fuel that has the advantages of easy storage and transport under
the right conditions. The two biggest markets for regional LNG are trucking fleets and
remote-site heat and/or power applications. Though in relative infancy in the United
States – particularly in the Pacific Northwest – LNG from a global perspective has a
longer track record and continues to be in high demand in energy import areas like Asia.
As a direct result of the LNG supply study, Intermountain received an emergency
supply request in late January 2013 to supply LNG to a small LNG-based distribution
utility located in southwestern Wyoming that temporarily had lost its supply of LNG.
The Idaho Public Utilities Commission (Commission) immediately granted emergency
authority for Intermountain to supply the needed LNG pursuant to Case No. INT-G-
13-01. Based on the efficiency review, the market study and the experience gained from
supplying the emergency LNG, the Company filed Case No. INT-G-13-02 to request
on-going authority from the Commission to sell “excess” LNG to non-utility customers.
4.7.3 Method of Forecasting
Intermountain utilized the results of the supply study (see Load Demand Curves
starting on page Error! Bookmark not defined.) in this IRP to determine how much
Nampa LNG would be needed for the core market during each year under the design
weather/high growth scenario. To determine the annual amount of “excess” LNG,
Intermountain begins with the annual core market withdrawal requirement and adds
1.2 million gallons of annual boiloff gas (boiloff naturally occurs with the warming of
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LNG), 300,000 gallons to maintain operational and training requirements at the Nampa
and Rexburg LNG facilities, and 500,000 gallons of “permanent” inventory to ensure
that all LNG does not boiloff. After summing those potential needs for each year in the
forecast, the remaining capacity is assumed to be available for non-utility LNG sales
customers. Table 72 shows the annual amount of Nampa LNG assumed to be available
for non-utility sales over the IRP period. For planning purposes, Intermountain will not
allow the tank inventory level to drop below the Net Utility Requirements shown below
at any time during December – February of any year since this is the peak demand
season for the Company’s distribution system. Further, should the need arise, all
volumes in the tank are always available to serve the core market. It should be noted
that the amount shown as “Available for Non-utility Sales” is a point-in-time figure.

Table 54: Nampa LNG Inventory Available for Non-Utility Sales

Gallons

2022

2023

2024

2025

2026
681,818 681,818 681,818 681,818 681,818
1,200,000 1,200,000 1,200,000 1,200,000 1,200,000
500,000 500,000 500,000 500,000 500,000
300,000 300,000 300,000 300,000 300,000
3,318,182 3,318,182 3,318,182 3,318,182 3,318,182
3,681,818 3,681,818 3,681,818 3,681,818 3,681,818

4.7.4 Benefits to Customers
Intermountain’s customers benefit from Intermountain’s LNG sales activities in several
different ways. First, as authorized in Order No. 35836 (Case No. INT-G-22-07)
Intermountain continues to defer 3.0¢ per gallon sold into a capital account and utilizes
that balance as it identifies capital costs that were accelerated due to increased use of
the Nampa LNG facility. That procedure directly reduces both rate base and
depreciation expense. Intermountain also continues to pass back to customers in its
annual PGA filing a credit to offset increased operating and maintenance costs as a
result of non-utility sales. That credit was previously 2.5¢ per gallon sold, but Order no.
35836 authorized the Company to increase the credit to 4.0¢ per gallon sold. Customers
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should see this increased benefit beginning with the 2024-2025 PGA to be filed in the
fall of 2024. Finally, Intermountain’s customers also benefit from the current margin
sharing mechanism which offsets gas purchase costs in the Company’s annual PGA.
Since April 2013, Intermountain has sold approximately 44 million gallons of LNG to
non-utility customers. These sales have provided approximately $1.1 million to offset
increased capital costs. Additionally, through its PGA the Company has credited to its
utility customers approximately $1.1 million to offset increased O&M costs and
approximately $6.5 million from the margin sharing mechanism. Further, the PGA
passback has reduced Intermountain’s gas costs every year since the PGA filed in
August 2013.
Another benefit comes from the fact that the Company has been selling much of its
LNG to markets which utilize it in Idaho. The sales primarily provide fuel to trucks that
formerly burned diesel as a fuel. LNG sales have increased economic growth in the state
and have also provided cleaner air benefits. The markets Intermountain sells LNG to
have expressed appreciation for a local, reliable, competitively priced fuel. Further,
many of the truck drivers have expressed a preference to load at Nampa as the design
and operations allow for more convenient and quicker trailer fills.

4.7.5 2021 Plant Downtime
During a maintenance review in early 2021, Intermountain discovered corrosion along
a welded seam in the outer steel tank. Because repairs could not occur with methane in
the tank, the facility was shut down in early May 2021 and the remaining LNG was
vaporized or allowed to boiloff. When the tank was completely empty and purged or
all remaining methane, the corrosion repairs were started. Repairs have been completed
and liquefaction is scheduled to begin in early January 2022. The first 2 million gallons
of liquefaction will be designated as utility LNG. Due to the limited liquefaction
window, non-utility liquefaction may not begin until several months into 2022 meaning
that non-utility sales may not begin again until the second quarter of 2022. The plant
downtime greatly minimized 2021 non-utility sales and will have a similar effect on 2022
sales.

4.7.6 On-Going Challenges
Since one of the biggest potential target markets for Intermountain’s non-utility sales is
“big rig” diesel fuel replacement, the price differential between LNG and diesel is
important. Low diesel prices tighten the cost differential between diesel and LNG and
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consequently the Company has had little ability to increase sales prices. In recent years
a comparatively low price differential has slowed growth in the LNG-based trucking
market.
A further challenge has been the lack of available large displacement LNG engines.
Because of the frequency and magnitude of roadway inclines, the mountain west
trucking industry prefers to rely on 15-liter engines. However, manufacturers do not
produce a 15-liter LNG engine, resulting in a challenge to utilize natural gas-powered
engines to haul the heaviest loads. Thus, lower diesel prices combined with the lack of
a 15-liter, LNG-powered engine has hampered growth in LNG sales demand. These
challenges have limited revenue growth in Intermountain’s non-utility LNG sales. As
the economy enters into a period of higher oil and gas prices, Intermountain will watch
the market for opportunity to grow non-utility sales.
The good news is that continuing efforts to work with existing LNG markets while also
marketing to new entities has resulted in Intermountain growing its sales every year
since 2013 until the temporary plant shutdown in 2021. Further, Intermountain looks
for opportunities to manage its inventory cost which has helped to support average
sales margins.

4.7.7 Safeguards
As described above, Intermountain takes steps to ensure that it maintains enough LNG
in the tank to provide for all projected customer withdrawal needs. This insulates the
core market from the risk of having no LNG should the need for needle peak
withdrawals arise. Intermountain has also committed to the Commission that all
volumes in the tank, regardless of the intended market, would always be available to
serve the core market should the need arise. Additionally, while the Company shares
LNG margins with its customers through the PGA, it also insulates its end-use
customers from any risk of loss due to non-utility sales.

4.7.8 Future
Intermountain continues to see growth in non-utility LNG sales and may even reach a
point where annual liquefaction levels are maximized. As the market continues to look
for ways to satisfy ever more stringent emissions standards, it is believed that LNG will
generate more interest. Looking to the future, the energy market has seen extremes in
supply and pricing. Current forecasts predict strong increases in oil and natural gas
prices which could have a short-term effect on margins once the tank is back in service.
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Barring major variances in price differentials or LNG demand destruction, the
Company expects that future sales volumes and margins will likely return to results seen
in 2020.
One advantage the Company has is the ability to store large amounts of LNG which
would last for an extended period of time for vaporization purposes. Because of its
storage capability, some markets look to Nampa as a backstop supplier when other
facilities might experience outages or planned downtime. Should the non-utility sales
market continue to show strong growth, the Company would likely not need more
storage capacity, but could address the need for more day- to-day sales volumes by
adding to or upgrading its liquefaction train in order to increase the daily production of
LNG.
The biggest disadvantage of the Nampa plant relates to the cost of liquefaction. Stand-
alone commercial LNG production facilities do not need large storage tanks, vaporizers
or other equipment designed to support peak shaving withdrawals and can therefore
operate at a lower cost. In addition, newer facilities utilize more recent technology that
can simply liquefy more efficiently than older facilities. A potential risk to
Intermountain’s LNG sales would be the construction of new commercial LNG
facilities in the region that would have lower operating costs which could result in the
loss of customers currently served by the Nampa facility or lower sales margins.

4.7.9 Recommendation
Notwithstanding the plant shutdown, challenges relating to growth in sales volumes
and a market facing flat margin growth will remain. A longer-term increase in diesel
prices vis-à-vis natural gas prices would provide more opportunity to grow both non-
utility LNG sales and margins. Intermountain’s Nampa LNG facility is located in an
area without direct competitors and the Company continues to build brand loyalty.
Based on the benefits to Intermountain and its utility customers, the lack of risk to its
customers and the ability to make more efficient use of the Nampa LNG assets,
Intermountain recommends that it continue to sell excess LNG to non-utility
customers.
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4.8 Infrastructure Replacement
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 three significant infrastructure replacement
projects. These replacement projects are not growth
driven.

4.8.1 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 2025. 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.

4.8.2 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 planning year 2024. The
pipeline was identified for replacement due to risks related to the Snake River and
Key Points
• Intermountain proactively
monitors its pipeline system
utilizing risk management
tools and engineering
analysis.
• Intermountain has identified
two crossings of high risk
where pipeline replacement
is needed.
• Intermountain utilizes an
Integrity Management
Program to identify, analyze
and monitor risks related to
the distribution system, and
to create programs that will
reduce or remove risks.
• Intermountain uses a risk
score and risk ratio to
prioritize high risk systems
for replacement.
• Intermountain also plans for
Transmission Re-
Confirmation and Shorted
Casing Replacement or
Abandonment Program
(SCRAP).

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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 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.

4.8.3 System Safety and Integrity Program (SSIP)
Intermountain utilizes an Integrity Management Program to identify, analyze and
monitor risks related to the distribution system, and to create programs that will reduce
or remove risks. In order to identify risks on the system, Intermountain utilizes system
knowledge based on known distribution systems characteristics, historical
maintenance information, available outside source information, and the use of subject
matter experts (SMEs) who are knowledgeable in operation, maintenance, design and
construction. From this information a risk model is used to manage and assess the risk
and to assign appropriate likelihood and consequence factors based on known system
knowledge and threats to the Company’s distribution system.
• Likelihood factors represent the possibility of a specific threat occurring on the
distribution system.
• Consequence factors are numerical weighting factors to represent consequences
that may be anticipated in case of an integrity issue.

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Intermountain uses a GIS-based risk model to calculate relative risk scores for
facilities. The risk model sums the assigned likelihood scores for each threat to
calculate a total likelihood factor within a 50-foot grid (raster). The same summing
calculation is also done for each of the assigned consequence factors within the same
50-foot grid. The total likelihood factor is then multiplied by the total consequence
factor to establish a total relative risk score for the grid.

= Likelihood Factor x Consequence Factor

Beginning in 2020, a System Safety and Integrity Program (SSIP) was implemented to
rank each distribution system utilizing a weighted average of the risk score per foot of
pipe. This weighted average is called the Risk Ratio and is used to prioritize high risk
systems for replacement.

io = ∑ (Total Relative Risk Score x Pipe Length) / ∑ Pipe Length
Results of the replacement projects on system Risk Ratios are trended and reviewed
as part of Intermountain’s Distribution Integrity Management Program (DIMP)
Performance Management program to ensure that integrity management activities are
having the desired effect of mitigating risks.
High risk pipeline segments that are targeted for replacement include:
• Early Vintage Plastic Pipe (EVPP) – Plastic mains, service lines, and associated
fittings installed earlier than 1/1/1995.
o Pre-1983 (i.e., Adyl-A): These pipelines include pipe installed prior to
1/1/1983 that may be susceptible to possible Low Ductile Inner Wall
(LDIW) characteristics that can result in slow crack growth and slit
failures, as documented by PHMSA–2004–19856.
o Post-1982: These pipelines were installed between 1/1/1983 and
12/31/1994 and are classified as EVPP to account for different inventory
levels and rates of new material adoption.
• Early Vintage Steel Pipe (EVSP) – Steel mains, service lines, and associated
fittings installed earlier than 1/1/1970. EVSP includes aging and/or obsolete
pipeline segments, bare steel or poorly coated pipe, pipe with unknown attributes
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or missing data, gas meters located indoors, and/or pipeline segments with
mechanical couplings and fittings.

Since 2013, Intermountain has been actively replacing segments of EVPP and EVSP
within its distribution system. In 2020 Intermountain started SSIP replacement in St.
Anthony, ID which was completed in 2022.Also in 2022, Intermountain completed
replacement in Sugar City, ID. in 2023, Intermountain completed replacement in
Parker, ID and is currently working on replacement in Boise, ID. SSIP replacement in
Boise is currently planned through 2027. Intermountain currently has approximately
$3.87 (2023) – $4.59 (2028) million budgeted for SSIP replacement annually, which is
used for replacing high risk distribution main and services. The SSIP replacement plan
will continue through the duration of the IRP.

4.8.4 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 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
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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 has approximately $1.42 (2024) – $2.45 (2028) million
budgeted for MAOP reconfirmation pipe replacement annually, which will be used for
replacing transmission pipeline segments where the records needed to substantiate the
MAOP are not TVC. MAOP reconfirmation replacement will continue through the
duration of the IRP.

4.8.5 Shorted Casing Replacement or Abandonment Program (SCRAP)
A steel carrier 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 to determine if the casing is shorted or electrically
isolated. Once a casing is determined to be shorted the casing's status remains shorted
until the shorted casing is mitigated and/or the casing is determined to be not shorted.
Shorted casings are required to be mitigated using one of the following methods:
1. Maintenance
2. Replacement
3. Abandonment/Removal
Intermountain currently has approximately $446,000 – $604,000 budgeted, from 2024
through 2028, 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.

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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.
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.

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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.
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.

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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.
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.
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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, which 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.
Maximum Daily Firm Quantity (MDFQ)
The contractual amount that Intermountain guarantees to deliver to 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
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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.
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
A 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.
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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.
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.