20211220Integrated Resource Plan.pdf

December 17, 2021
Ms. Jan Noriyuki
Commission Secretary Idaho Public Utilities Commission P.O. Box 83720 Boise, ID 83720-0074
RE: Case No. INT-G-21-06
Dear Ms. Noriyuki:
Attached for consideration by this Commission is an electronic submission of Intermountain Gas Company’s (“Intermountain”) 2021 Integrated Resource Plan (“IRP”). An original and seven (7) copies of the 2021 IRP will be hand-delivered within a few days.
Intermountain respectfully requests that the Commission acknowledge the 2021 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,
Lori A. Blattner
Director, Regulatory Affairs Intermountain Gas Company
Enclosures
cc: Mark Chiles Preston Carter
RECEIVED
2021 DEC 20 AM 9:08
IDAHO PUBLIC
UTILITIES COMMISSION

Intermountain Gas Company
Integrated Resource Plan
2021 – 2026

Intermountain Gas Company
Table of Contents
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Table of Contents

Overview .............................................................................................................. 1
Executive Summary ............................................................................................................................. 1
About the Company .............................................................................................................................. 1
Customer Base ...................................................................................................................................... 2
The IRP Process ..................................................................................................................................... 2
Intermountain Gas Resource Advisory Committee .............................................................................. 4
Summary ............................................................................................................................................... 5
About the Natural Gas Industry ....................................................................................................... 7
Natural Gas and the National Energy Picture ....................................................................................... 7
The Direct Use of Natural Gas ............................................................................................................... 8
Clean Energy Future .............................................................................................................................. 9
Demand .............................................................................................................. 10
Demand Forecast Overview ............................................................................................................ 10
Residential & Commercial Customer Growth Forecast ........................................................... 11
Household Projections ........................................................................................................................ 15
The Base Case Economic Growth Scenario ......................................................................................... 16
Population and Household Growth .................................................................................................... 19
The High and Low Economic Growth Scenarios ................................................................................. 21
Forecast Households ........................................................................................................................... 24
Market Share Rates ............................................................................................................................. 26
Conversion Rates ................................................................................................................................ 28
Commercial Customer Forecast .......................................................................................................... 30
Heating Degree Days & Design Weather ..................................................................................... 31
Normal Degree Days ........................................................................................................................... 31
Design Degree Days ............................................................................................................................ 31
Peak Heating Degree Day Calculation ................................................................................................. 32
Base Year Design Weather .................................................................................................................. 32
Area Specific Degree Days .................................................................................................................. 34
Usage Per Customer ......................................................................................................................... 35
Methodology ....................................................................................................................................... 35
Usage per Customer by Geographic Area ........................................................................................... 35
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Model Validation ................................................................................................................................. 36
Conclusion ........................................................................................................................................... 36
Large Volume Customer Forecast ................................................................................................. 37
Introduction ........................................................................................................................................ 37
Method of Forecasting ........................................................................................................................ 38
Forecast Scenarios .............................................................................................................................. 39
Contract Demand ................................................................................................................................ 39
“Load Profile” vs MDFQ ...................................................................................................................... 40
System Reliability ................................................................................................................................ 40
General Assumptions .......................................................................................................................... 41
Base Case Scenario Summary ............................................................................................................. 41
High Growth Forecast Summary ......................................................................................................... 42
Low Growth Forecast Summary .......................................................................................................... 44
Supply & Delivery Resources ............................................................................ 48
Supply & Delivery Resources Overview ........................................................................................ 48
Traditional Supply Resources .......................................................................................................... 49
Overview ............................................................................................................................................. 49
Background ......................................................................................................................................... 49
Gas Supply Resource Options ............................................................................................................. 50
Shale Gas ............................................................................................................................................. 52
Supply Regions .................................................................................................................................... 53
Export LNG .......................................................................................................................................... 56
Types of Supply ................................................................................................................................... 56
Pricing .................................................................................................................................................. 57
Storage Resources ............................................................................................................................... 58
Interstate Pipeline Transportation Capacity ....................................................................................... 63
Supply Resources Summary ................................................................................................................ 66
Capacity Release & Mitigation Process ......................................................................................... 67
Overview ............................................................................................................................................. 67
Capacity Release Process .................................................................................................................... 68
Mitigation Process .............................................................................................................................. 69
Non-Traditional Supply Resources ................................................................................................. 70
Lost and Unaccounted For Natural Gas Monitoring ................................................................. 75
Intermountain Gas Company
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Billing and Meter Audits ..................................................................................................................... 76
Meter Rotation and Testing ................................................................................................................ 76
Leak Survey ......................................................................................................................................... 76
Damage Prevention and Monitoring .................................................................................................. 77
Advanced Metering Infrastructure ..................................................................................................... 79
Weather and Temperature Monitoring .............................................................................................. 79
Summary ............................................................................................................................................. 80
Core Market Energy Efficiency ........................................................................................................ 81
Residential & Commercial Energy Efficiency Programs ...................................................................... 81
Conservation Potential Assessment.................................................................................................... 81
Therm Savings ..................................................................................................................................... 83
Ensuring an Energy Efficient Future .................................................................................................... 86
Large Volume Energy Efficiency ..................................................................................................... 88
Avoided Costs ..................................................................................................................................... 90
Overview ............................................................................................................................................. 90
Costs Incorporated .............................................................................................................................. 90
Understanding Each Component ........................................................................................................ 91
Optimization ...................................................................................................... 92
Distribution System Modeling ......................................................................................................... 92
Overview ............................................................................................................................................. 92
Modeling Methodology ...................................................................................................................... 93
Capacity Enhancements.................................................................................................................... 94
Overview ............................................................................................................................................. 94
Capacity Enhancement Options .......................................................................................................... 94
Canyon County .................................................................................................................................... 96
State Street Lateral ........................................................................................................................... 100
Central Ada County ........................................................................................................................... 104
Sun Valley Lateral .............................................................................................................................. 108
Idaho Falls Lateral ............................................................................................................................. 111
Summary ........................................................................................................................................... 115
Load Demand Curves ...................................................................................................................... 118
Customer Growth Summary Observations – Design Weather – All Scenarios ................................. 119
Core Customer Distribution Sendout Summary – Design and Normal Weather – All Scenarios ..... 120
Intermountain Gas Company
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Projected Capacity Deficits – Design Weather – All Scenarios ......................................................... 123
2019 IRP vs. 2021 IRP Common Year Comparisons .......................................................................... 126
Resource Optimization ................................................................................................................... 139
Introduction ...................................................................................................................................... 139
Functional Components of the Model .............................................................................................. 139
Demand SENDOUT® Optimization Model ......................................................................................... 139
Model Structure ................................................................................................................................ 140
Demand Area Forecasts .................................................................................................................... 141
Supply Resources .............................................................................................................................. 144
Transport Resources ......................................................................................................................... 146
Model Operation ............................................................................................................................... 147
Special Constraints ............................................................................................................................ 148
Model Inputs ..................................................................................................................................... 148
Model Results ................................................................................................................................... 150
Summary ........................................................................................................................................... 152
Planning Results ................................................................................................................................ 154
Overview ........................................................................................................................................... 154
Distribution System Planning ............................................................................................................ 154
2019 IRP vs. 2021 IRP Common Year Comparisons .......................................................................... 158
Upstream Modeling .......................................................................................................................... 165
Conclusion ......................................................................................................................................... 166
Non-Utility LNG Forecast .............................................................................................................. 167
Introduction ...................................................................................................................................... 167
History ............................................................................................................................................... 167
Method of Forecasting ...................................................................................................................... 168
Benefits to Customers ....................................................................................................................... 168
2021 Plant Downtime ....................................................................................................................... 169
On-Going Challenges ......................................................................................................................... 169
Safeguards ......................................................................................................................................... 170
Future ................................................................................................................................................ 170
Recommendation .............................................................................................................................. 171
Infrastructure Replacement ........................................................................................................... 172
American Falls Neely Bridge Snake River Crossing ........................................................................... 172
Intermountain Gas Company
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Rexburg Snake River Crossing ........................................................................................................... 172
System Safety and Integrity Program (SSIP) ..................................................................................... 173
Glossary ............................................................................................................ 175

Intermountain Gas Company
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List of Tables

Table 1: Forecast New Customers ...................................................................................................................................... 15 Table 2: Forecast Total Customers ..................................................................................................................................... 15 Table 3: Regional Conversion Rate .................................................................................................................................... 28 Table 4: Monthly Heating Degree Days ............................................................................................................................. 34 Table 5: Large Volume Therm Forecast - Base Case Scenario .......................................................................................... 41 Table 6: Large Volume Therm Forecast - High Growth Scenario ..................................................................................... 43 Table 7: Large Volume Therm Forecast - Low Growth Scenario ...................................................................................... 44 Table 8: Storage Resources ................................................................................................................................................. 62 Table 9: Northwest Pipeline Transport Capacity ............................................................................................................... 64 Table 10: 2018 - 2020 Billing and Meter Audit Results ...................................................................................................... 76 Table 11: Canyon County Alternative Summary ................................................................................................................. 99 Table 12: State Street Alternative Summary ..................................................................................................................... 103 Table 13: Central Ada County Alternative Summary ....................................................................................................... 108 Table 14: Sun Valley Lateral Alternative Summary .......................................................................................................... 111 Table 15: Idaho Falls Lateral Alternative Summary ........................................................................................................ 114 Table 16: AOI Capacity Summary and Timings ............................................................................................................... 116 Table 17: Nampa LNG Inventory Available for Non-Utility Sales ................................................................................... 168

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 ................................................................................................. 13 Figure 4: Customer Addition Forecast - Residential & Commercial ................................................................................. 14 Figure 5: Annual Additional Customers - Base Case: 2019 IRP vs 2021 IRP ................................................................... 14 Figure 6: Annual Additional Households Forecast ............................................................................................................ 25 Figure 7: Additional Households Forecast - Base Case: 2019 IRP vs 2021 IRP .............................................................. 25 Figure 8: Market Penetration Rate - By District ................................................................................................................ 26 Figure 9: Residential New Construction Growth ................................................................................................................ 27 Figure 10: Annual Residential New Construction Growth - Base Case: 2019 IRP vs 2021 IRP ...................................... 27 Figure 11: Annual Residential Conversion Growth ............................................................................................................ 29 Figure 12: Annual Residential Conversion Growth – Base Case: 2019 IRP vs. 2021 IRP ............................................... 29 Figure 13: Additional Commercial Customers ................................................................................................................... 30 Figure 14: Annual Additional Commercial Customers – Base Case: 2019 IRP vs. 2021 IRP .......................................... 30 Figure 15: Design Heating Degree Days ............................................................................................................................ 33 Figure 16: LV Therms - 2019 IRP Forecast vs Actuals ...................................................................................................... 38 Figure 17: Large Volume Customer Survey Cover Letter .................................................................................................. 46 Figure 18: Large Volume Customer Survey Questions....................................................................................................... 47 Figure 19: Natural Gas Sources ......................................................................................................................................... 50 Figure 20: Natural Gas Consumption by Sector ................................................................................................................. 51 Figure 21: Shale Gas Production Trend ............................................................................................................................. 51 Figure 22: US Lower 48 States Shale Plays ....................................................................................................................... 53
Intermountain Gas Company
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Figure 23: Supply Pipeline Map ......................................................................................................................................... 54 Figure 24: Natural Gas Trade ............................................................................................................................................. 56 Figure 25: Intermountain Price Forecast as of 04/22/2021 ............................................................................................... 58 Figure 26: Intermountain Storage Facilities ...................................................................................................................... 59 Figure 27: Pacific Northwest Pipelines Map ...................................................................................................................... 65 Figure 28: Intermountain LAUF Statistics .......................................................................................................................... 75 Figure 29: Damage Rates per 1,000 Locates by Region .................................................................................................... 78 Figure 30: Intermountain Locate Requests by Region ........................................................................................................ 78 Figure 31: Intermountain Total Damages by Region ......................................................................................................... 79 Figure 32: Categories of Potential Savings ........................................................................................................................ 82 Figure 33: Key Steps and Inputs in Study Methodology ..................................................................................................... 83 Figure 34: Cumulative Therm Savings ................................................................................................................................ 84 Figure 35: Cumulative Therm Savings, Base Achievable Scenario .................................................................................... 84 Figure 36: Achievable Savings by Segment 2021 - 2026 .................................................................................................... 85 Figure 37: Achievable Savings by Application 2021 - 2026 ............................................................................................... 85 Figure 38: Commercial Energy Efficiency Rebates ............................................................................................................ 86 Figure 39: Large Volume Website Login ............................................................................................................................ 88 Figure 40: Natural Gas Usage History ............................................................................................................................... 89 Figure 41: Canyon County Capacity Limiter ...................................................................................................................... 96 Figure 42: Canyon County Alternative One ....................................................................................................................... 97 Figure 43: Canyon County Alternative Two ....................................................................................................................... 97 Figure 44: Canyon County Alternative Three ..................................................................................................................... 98 Figure 45: Canyon County Alternative Four ...................................................................................................................... 99 Figure 46: State Street Capacity Limiter .......................................................................................................................... 101 Figure 47: State Street Alternative One ............................................................................................................................ 102 Figure 48: State Street Alternative Two ............................................................................................................................ 103 Figure 49: Central Ada County Capacity Limiter ............................................................................................................ 105 Figure 50: Central Ada County Alternative One .............................................................................................................. 105 Figure 51: Central Ada County Alternative Two .............................................................................................................. 106 Figure 52: Central Ada County Alternative Three ........................................................................................................... 107 Figure 53: Sun Valley Capacity Limiter ........................................................................................................................... 109 Figure 54: Sun Valley Lateral Alternative One ................................................................................................................ 110 Figure 55: Idaho Falls Lateral Capacity Limiter ............................................................................................................. 112 Figure 56: Idaho Falls Lateral Alternative One ............................................................................................................... 113 Figure 57: Idaho Falls Lateral Alternative Two ............................................................................................................... 114 Figure 58: IGC Natural Gas Modeling System Map ........................................................................................................ 140 Figure 59: IGC Laterals from Zone 24 ............................................................................................................................. 142 Figure 60: Total Company Design Base 2021 .................................................................................................................. 143 Figure 61: IGC Supply Model Example ............................................................................................................................ 144 Figure 62: IGC Storage Model Example .......................................................................................................................... 145 Figure 63: IGC DSM Model Example ............................................................................................................................... 146 Figure 64: IGC Transport Model Example ....................................................................................................................... 147 Figure 65: Transport Input Summary ............................................................................................................................... 149 Figure 66: Lateral Summary by Year ................................................................................................................................ 151 Figure 67: Annual Traditional Supply Resources Results ................................................................................................ 151 Figure 68: Annual Transportation Resources Results ...................................................................................................... 152 Figure 69: LDC Design Base Case – Canyon County Lateral ......................................................................................... 154 Figure 70: LDC Design Base Case – State Street Lateral ................................................................................................ 155 Figure 71: LDC Design Base Case – Central Ada Lateral .............................................................................................. 156
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Figure 72: LDC Design Base Case – Sun Valley Lateral ................................................................................................. 157 Figure 73: LDC Design Base Case – Idaho Falls Lateral................................................................................................ 158 Figure 74: 2026 Design Base Case – Total Company ...................................................................................................... 165
Intermountain Gas Company
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Executive Summary

Overview
Executive Summary

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.

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. At the end of 2020, Intermountain
served approximately 387,000 total customers in 76 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
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Executive Summary

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.

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.

Demand
As a starting point, Intermountain develops base case, high growth, and low growth scenarios to
project the customer demand on its system for both core market and large volume customers.
The core market includes residential and commercial customers. Large volume customers are
high usage customers that are not eligible for residential or commercial service.
For the core market, the first step involves forecasting customer growth for both residential and
commercial customers. Next, Intermountain develops design weather. Then the Company
determines the core market usage per customer using historical usage, weather and geographic
data. The usage per customer number is then applied to the customer forecast under design
weather conditions to determine the core market demand.
To forecast both therm usage and contract demand for large volume customers, the Company
analyzes historical usage, economic trends, and direct input from large volume customers. This
approach is appropriate given the small population size of these customer classes. Because large
Intermountain Gas Company
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Executive Summary

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.

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.

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
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Executive Summary

Intermountain Gas Resource Advisory Committee
To enhance the Integrated Resource Plan development, the Company established the
Intermountain Gas Resource Advisory Committee (IGRAC). The intent of the committee is to
provide a forum through which public participation can occur as the IRP is developed.
Advisory committee members were solicited from across Intermountain’s service territory as
representatives of the communities served by Intermountain. Exhibit 1, Section A, is a sample of
the invitation to join the committee. Committee members have varied backgrounds in regulation,
economic development, and business. A full listing of IGRAC members is included in Exhibit 1,
Section A.
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 2021 between the months of March and July. Included in Exhibit 1,
Sections B, C, and D are sample invitations and copies of the presentations from the meetings.

Figure 1: The IRP Process
Intermountain Gas Company
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Executive Summary

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.

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.
Intermountain Gas Company
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Executive Summary

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Figure 2: Intermountain Gas System Map
Intermountain Gas Company
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About the Natural Gas Industry

About the Natural Gas Industry

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.1 The Environmental
Protection Agency’s (EPA) “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2019”
reveals that once again natural gas distribution systems have a small emissions footprint shaped
by a declining trend. Methane emissions from the natural gas industry account for only 2.7
percent of total greenhouse gas emissions. These annual emissions have declined from 69
percent of the total in 1990 even as natural gas distribution companies added more than 788,000
miles of pipeline nationally to serve 21 million more customers.2 A Washington State University
study found that as little as 0.1% of the natural gas delivered nationwide is emitted from local
distribution systems.3
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.4
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 Northwest Gas Association, households that use natural gas for
heating, cooking and clothes drying spend an average of $874 less per year than homes using
electricity for those same applications.5 The American Gas Association also reported that for
residential customers, the cost of natural gas has been lower than the cost of propane, fuel oil,
or electricity since 2010, and is forecasted to stay low through 2040.6
According to the American Gas Association, in the United States natural gas currently meets more
than 25% of the nation’s energy needs, providing energy to almost 75 million residential,

1 https://www.aga.org/contentassets/4c04bee66b4648f086bcde31e4815e4e/building-the-value-of-natural-gas---a-fact-base-may-2020.pdf
2 https://www.aga.org/research/reports/epa-updates-to-inventory-ghg/
3 https://www.aga.org/policy/Environment/infographic-emissions-from-systems-operated-by-natural-gas-
utilities-continue-to-decline/
4 https://www.ingaa.org/File.aspx?id=28478
5 https://www.nwga.org/wp-content/uploads/2021/03/NWGA_Facts_2021_Final.pdf
6 https://www.aga.org/natural-gas/affordable/
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About the Natural Gas Industry

commercial and industrial customers.7 Natural gas is now even more plentiful than ever in North
America, with an estimated 84 year supply at current consumption levels.8 Even with this
plentiful supply, however, it remains vital that all natural gas customers use the energy as wisely
and as efficiently as possible.

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 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.

7 https://www.aga.org/globalassets/2019-natural-gas-factsts-updated.pdf
8 https://www.eia.gov/tools/faqs/faq.php?id=58&t=8
Intermountain Gas Company
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About the Natural Gas Industry

Clean Energy Future
Natural gas is not only safe, reliable and affordable, but the natural gas distribution system will
also be a critical component in delivering clean energy in the future. Intermountain is actively
involved in the research and development of low- and zero-carbon energy technologies through
its participation in Gas Technology Institute (GTI) and the Low-Carbon Resources Initiative (LCRI).
LCRI is a joint venture of GTI and the Electric Power Research Institute. Its mission is to accelerate
the deployment of the low- and zero-carbon energy technologies that will be required for deep
decarbonization. LCRI is specifically targeting advances in the production, distribution, and
application of low-carbon, alternative energy carriers and the cross-cutting technologies that
enable their integration at scale. These energy carriers - which include hydrogen, ammonia,
synthetic fuels, and biofuels - are needed to enable affordable pathways to achieve deep carbon
reductions across the energy economy. The LCRI is focused on technologies that can be
developed and deployed beyond 2030 to support the achievement of a net zero emission
economy by 2050.
Intermountain is also playing an important role in the growth and development of the emerging
Renewable Natural Gas (RNG) industry. The Company’s RNG Facilitation agreement allows
Intermountain to provide access to its distribution system for RNG producers to transport RNG
to their end use customers. RNG takes a waste stream that is currently emitting greenhouse
gasses, captures it, and puts it to a beneficial end use. Although RNG is currently more expensive
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.

Intermountain Gas Company
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Demand Forecast Overview

Demand
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. 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.
• 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.
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Residential & Commercial Customer Growth Forecast

Residential & Commercial Customer Growth Forecast

This section of Intermountain’s IRP describes and summarizes the residential and commercial
customer growth forecast for the years 2021 through 2026. 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.
The Company’s customer growth forecast includes three key components:
1. Residential new construction customers,
2. Residential customers who convert to natural gas from an alternative fuel, and
3. Commercial customers
To calculate the number of residential customers added each year, the annual change in
households for each county in the Company’s service territory is determined using the Idaho
Economics Winter 2020 Economic Forecast for the State of Idaho by John S. Church (‘20 Forecast),
dated April 2021 (see Exhibit 2, Section A). Using the assumption that a new household means a
new dwelling is needed, the annual change in households by county is multiplied by
Intermountain’s market penetration rate in that region to determine the additional residential
new construction customers. Next, that number is multiplied by the Intermountain conversion
rate, which is the anticipated percentage of conversion customers relative to new construction
customers in those locales. This results in the number of expected residential conversion
customers, which when added to the residential new construction numbers, equals the total
expected additional residential customers by county.
To accurately estimate growth for the State Street AOI, which contains a small portion of Canyon
County and a large portion of Ada County, an additional estimate is utilized. The Community
Planning Association of Southwest Idaho (COMPASS) conducts annual forecasts based on defined
‘Traffic Analysis Zones’ (TAZ) within Ada County. According to COMPASS, the TAZ that coincides
with the State Street AOI boundary is expected to grow 3.59% per year over the next 5 years.
This annual growth rate is applied to the current customer count within that boundary to derive
the estimated growth of the State Street AOI over the same time period.
The Central Ada AOI sits entirely in Ada County. Using the same methodology as described above,
the Central Ada AOI growth was calculated to be 1.85% per year.
The commercial customers are forecasted in a different manner. Intermountain utilizes an
ARIMA model which incorporates employment forecasts as an explanatory variable. An ARIMA
model is an autoregressive integrated moving average model that is used on time series data to
better predict future points. The employment data measures actual and forecasted full- and
part-time jobs by place of work. Generally, when employment is increasing, commercial
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Residential & Commercial Customer Growth Forecast

customer counts are also increasing, thus, the reason for including employment as an
explanatory variable. The Company modeled households as an explanatory variable as well but
found that employment provided better results. Each County in Intermountain’s service territory
is modeled separately. The commercial customer forecast model is as follows:
𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶= 𝛼𝛼0 + 𝛼𝛼1𝐸𝐸𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶+𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴(𝐸𝐸,𝑑𝑑,𝑞𝑞)

Where:
• 𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶=𝐶𝐶𝐶𝐶𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶 𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐸𝐸𝐶𝐶𝐶𝐶𝐶𝐶 𝑏𝑏𝑏𝑏 𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝑏𝑏
• 𝐸𝐸𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶=𝐸𝐸𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝑏𝑏𝐸𝐸𝐶𝐶𝐶𝐶𝐶𝐶 𝑏𝑏𝑏𝑏 𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝑏𝑏
• 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴(𝐸𝐸,𝑑𝑑,𝑞𝑞)=𝐴𝐴𝐶𝐶𝑑𝑑𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶 𝐶𝐶ℎ𝐶𝐶𝐶𝐶 𝐶𝐶ℎ𝐶𝐶 𝐸𝐸𝐶𝐶𝑑𝑑𝐶𝐶𝐶𝐶 ℎ𝐶𝐶𝐶𝐶 𝐸𝐸 𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝑎𝑎𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝑎𝑎𝐶𝐶 𝐶𝐶𝐶𝐶𝐶𝐶𝐸𝐸𝐶𝐶,𝑑𝑑 𝑑𝑑𝐶𝐶𝑑𝑑𝑑𝑑𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶 𝐶𝐶𝐶𝐶𝐶𝐶𝐸𝐸𝐶𝐶,𝐶𝐶𝐶𝐶𝑑𝑑 𝑞𝑞 𝐸𝐸𝐶𝐶𝑎𝑎𝐶𝐶𝐶𝐶𝑎𝑎 𝐶𝐶𝑎𝑎𝐶𝐶𝐶𝐶𝐶𝐶𝑎𝑎𝐶𝐶 𝐶𝐶𝐶𝐶𝐶𝐶𝐸𝐸𝐶𝐶

Exhibit 2 shows the Company’s residential and commercial customer forecast.
Similar to the 2019 IRP, which demonstrated a continued resurgence in the housing market
Intermountain’s growth projections continue to stay strong. The ’20 Forecast household numbers
are employed to determine the relative overall number of customer additions, as well as the
distribution of those customer additions across the Company’s service territory.
The following graph (Figure 3) depicts the relationship, or shape, of customer additions by AOI:

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Residential & Commercial Customer Growth Forecast

Figure 3: Base Case Forecast Growth by Area of Interest

The ’20 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.
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Residential & Commercial Customer Growth Forecast

Figure 4: Customer Addition Forecast - Residential & Commercial
The following graph (Figure 5) shows the difference in base case annual additional customers
between the 2019 and 2021 IRP forecast years common to both studies:

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

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Residential & Commercial Customer Growth Forecast

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
Forecast New Customers
2021 2022 2023 2024 2025 2026
LOW
GROWTH 5,566 6,801 7,002 6,957 6,842 6,505
BASE CASE
HIGH
GROWTH 16,733 13,704 14,978 15,442 15,399 15,768

Table 2: Forecast Total Customers
Forecast Total Customers
2021 2022 2023 2024 2025 2026
LOW
GROWTH 392,884 399,685 406,686 413,644 420,486 426,991
BASE
CASE 400,790 412,012 423,620 435,236 446,032 457,212
HIGH
GROWTH 404,051 417,756 432,734 448,176 463,575 479,342

The following sections explore more fully the different components of the customer forecast,
including the ‘20 Forecast, market penetration and conversion rates, and commercial customer
growth.

Household Projections
The ’20 Forecast provides county by county projections of output, employment and wage data
for 21 industry categories for the state of Idaho, as well as population and household forecasts.
This simultaneous equation model uses personal income and employment by industry as the
main economic drivers of the forecast. The model also utilizes forecasts of national inputs and
demand for those sectors of the Idaho economy having a national or international exposure.
Industries that do not have as large a national profile and are thus serving local communities and
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demand are considered secondary industries. Local economic factors, rather than the national
economy, determine demand for these products.
The ’20 Forecast uses two methods for population projections: (1) a cohort-component
population model in which annual births and deaths are forecast, the net of which is either added
to or subtracted from the population; and (2) an econometric model which forecasts population
as a function of economic activity. The two forecasts are then compared and reconciled for each
quarter of the forecast. Migration into or out of the state is derived as a result of this
reconciliation.
As previously mentioned, the ‘20 Forecast provides three scenarios: (1) base case, (2) high
growth, and (3) low growth. The base case scenario assumes a normal amount of economic
fluctuation and a normal business cycle. This becomes the standard against which changes in
customer growth, as affected by the low and high growth scenarios can be measured.

The Base Case Economic Growth Scenario
In the Base Case Scenario of the Winter 2020 Idaho Economic Forecast it is 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
51,000 jobs (7.8%) 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 74,300 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 2020 to 2045 forecast period.
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Total non-agricultural employment in the State is projected to increase by 709,000 (an annual
average increase of 2.5 percent per year) over the 2020 to 2045 period. Ada and Canyon counties
are projected to capture the majority of the non-ag employment gains with a projected increase
of 460,000 non-ag jobs in the two counties, an annual average increase of 3.4 percent per year
over the 2020 to 2045 period. During those twenty-five years Ada and Canyon counties are
projected to account for nearly 64.8 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 2020 to 2045 forecast period non-ag
employment in these the Eastern Idaho counties is projected to increase by 86,400 jobs, a 2.2
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 2020 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 last twenty years food processing employment in Ada, Canyon, Twin Falls, and Jerome
counties had been increasing, largely on the strength of the expansion of the dairy industry in
the state. Job gains in the dairy products manufacturing sector have been strong. In the forecast
period it is expected that the dairy products manufacturing firms will continue to post job gains.
At the same time, it is projected that the vegetable processing firms in Southern Idaho will, over
the 2020 to 2045 forecast period, experience further job losses as processing plant consolidation,
processing automation, and production efficiencies continue. The total effect of these trends in
the food processing industry is that it is not projected that the food processing sector will be a
significant contributor to future manufacturing employment gains in Idaho.
A new dynamic seen in the state over the last ten years is an increased number of small to
medium size manufacturing firms relocating from other states to Idaho. Many of these firms are
seeking lower costs of production, less regulation, and improved business climate; and many of
those firms are from California.

Employment in Idaho's traditional Lumber and Wood Products manufacturing sector slipped in
the 2008 Great Recession. It has not recovered and its unlikely that it will recover with the
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possible exception of the production of higher value-added processed wood products. Future job
gains in the Lumber and Wood Products manufacturing sector is projected to be minimal over
the 2020 to 2045 forecast period. Statewide employment in Stone, Clay, and Glass Products and
Fabricated Metal Products manufacturing is expected to increase in proportion to population and
household growth in the state. Idaho's Electronics and Machinery manufacturing sectors are not
expected to regain the jobs lost during the last recession. No new large-scale machinery or
electronics manufacturing facilities are assumed to be located in Idaho during the 2020 to 2045
forecast period.
In the 2020 to 2045 forecast period manufacturing employment in Idaho is projected to increase
by nearly 23,400 jobs; an annual average gain of close to 2.0 percent per year. This represents a
continuation of the pace of manufacturing employment gains that the state experienced from
the low points of the 2008 Great Recession. Manufacturing employment in Ada and Canyon
counties is projected to capture nearly 17,000 (about 75 percent) of the state’s projected 2020
to 2045 growth in manufacturing employment.
Statewide employment in the Transportation, Trade, and Utilities industries is projected to
increase by nearly 87,600 jobs over the 2020 to 2045 forecast period; an annual average increase
of nearly 2.0 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 63,400 over the forecast period, representing 72.0
percent of the projected statewide employment gains in the sector. A new Amazon fulfillment
facility in Canyon County and a second Amazon facility (different than the Canyon County
fulfillment center) in Ada County are expected to increase employment dramatically in the near
term.
The service industries in Idaho have been the fastest growing in terms of employment gains over
the last twenty years. Idaho employment in the Professional and Business Services sector
increased by nearly 32,000 jobs between 2000 and mid-year 2019; an annual average increase of
2.1 percent per year. Ada and Canyon counties captured nearly 61.0 percent of the State’s
Professional and Business Services employment growth between 2000 and mid-year 2019. In the
2020 to 2045 forecast period Professional and Business Services employment is projected to
increase by 130,800; an annual average compound rate of 3.6 percent per year. Historically the
Professional and Business 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.

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Idaho employment in Educational and Health Services increased by nearly 57,400 jobs between
2000 and mid-year 2019; an annual average increase of 3.7 percent per year. Ada and Canyon
counties captured 29,200, nearly 50.8 percent, of the state’s Educational and Health Services
employment growth between 2000 and mid-year 2019. In the 2020 to 2045 forecast period
Educational and Health Services employment is projected to increase by 168,800; an annual
average compound rate of 3.7 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 2020 to 2045 forecast
period. In the counties along Intermountain Gas Company’s Idaho Falls Lateral the Educational
and Health Services sector is projected add 14,700 jobs over the 2020 to 2045 forecast period.
Idaho employment in Leisure and Hospitality Services increased by nearly 26,700 jobs between
2000 and mid-year 2019; an annual average increase of 2.1 percent per year. Ada and Canyon
counties captured 13.200, nearly 49.3 percent, of the state’s Leisure and Hospitality Services
employment growth between 2000 and mid-year 2019. In the 2020 to 2045 forecast period
Leisure and Hospitality Services employment is projected to increase by 64,900; an annual
average compound rate of 2.4 percent per year. In the counties along Intermountain Gas
Company’s Idaho Falls Lateral the Leisure and Hospitality Services sector is projected to add
nearly 6,700 jobs over the 2020 to 2045 forecast period.
Employment in the Government sector increased by 7,700 jobs between 2000 and mid-year
2019; an annual average increase of 0.3 percent per year. Government employment gained
10,200 jobs in Ada and Canyon counties between 2000 and mid-year 2019, 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 2020 to 2045 forecast period
Government employment is projected to increase by 110,900; an annual average compound rate
of 2.7 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.

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 last 5 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.
While the COVID-19 pandemic has caused significant economic hardship in the country and the
state it initially appears that Idaho has fared better than many other states. Unemployment in
Idaho surged dramatically in March and April of 2020. But, in short order the state exhibited that
the COVID-19 induced recession in Idaho was going to be a V-shaped recession with an initial
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sharp downturn in economic activity and thereafter a quick recovery in economic activity. And
while there are many people in Idaho who are still under tremendous economic pressures
because of the COVID-19 pandemic the state has nearly recovered to its pre-pandemic level of
total employment.
The latest US Census Bureau’s estimates of 2020 state populations (this is an estimate that is not
based on the official 2020 US Census tabulation) has Idaho ranked as the fastest growing state in
the nation with an annual average population increase of 2.12%. At this time the US Census
Bureau’s estimate of Idaho’s 2020 population is 1,839,000.
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 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 2020 to 2045 forecast period Idaho's population will increase by
1,283,000 reaching a total population of 3,024,600 by the year 2045, an annual average pace of
2.2 percent per year. The number of households in the state is expected to increase by
approximately 366,000 over the 2020 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 881,000
and 410,500, respectively, by the year 2045. This represents an increase of 433,400 in Ada County
population and a 179,500 increase in Canyon County population over the 2020 to 2045 forecast
period. In total, population growth in Ada and Canyon counties are projected to account for 47.9
percent of the 2020 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 66,000, 49,100, 49,200 and 25,300, respectively, a total population
increase for the four counties of 189,600 over the 2020 to 2045 forecast period. These four
Eastern Idaho counties are projected to account for 14.8 percent of the state’s population growth
over the forecast period. A total growth in population and households of 140,400 persons and
61,630 households is projected in the eight counties along the Idaho Falls Lateral over the 2020
to 2045 forecast period.

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The High and Low Economic Growth Scenarios
The high growth and low growth scenarios of the ‘20 Forecast present alternative views of the
economic future of Idaho and its 44 counties. The high growth scenario of the ‘20 Forecast
presents a vision of a more rapidly growing economy in Idaho. The high growth scenario average
annual compound rate of population growth from 2020 to 2045 is 2.5% per year.
Alternatively, the low growth Scenario of the ‘20 Forecast presents a slower economic outlook
for the Idaho economy. In the low growth scenario, Idaho’s population is exhibiting an annual
average compound growth rate of 1.4% per year from 2020 to 2045.
An examination of the possible economic and demographic events that could produce the
economic and population growth projected in the high and low growth scenarios are outlined
below.

The High Growth Economic Scenario
The High Growth Scenario of the ‘20 Forecast assumes that Idaho will be a more attractive
environment for the relocation of firms from other states. Many small to medium businesses
currently operating in California, Oregon, and Washington are examining their options to relocate
to other areas with lower taxes, operating costs, and regulation. This is not a new phenomenon.
In the 1990’s many firms relocated some or all of their operations from California and spurred on
economic growth in Nevada and Arizona. In the next decade (2000 to 2010) this trend continued
with Nevada, Arizona, and Utah seeing an influx of firms and an increase in population in-
migration. Idaho and Southwestern Oregon also captured a portion of economic and population
growth caused by this dynamic. The High Growth Scenario assumes that this phenomenon will
continue, and that Idaho will capture a larger share of that relocation and growth dynamic.
The High Growth Scenario projects an Idaho population of 3,368,200 in the year 2045. The High
Scenario projected population at the end of the forecast period is 11.4 percent (343,500) higher
than in the Base Scenario forecast. As is the case in the Base Scenario forecast Ada and Canyon
Counties realize the lion’s share of Idaho’s population growth. The 2045 population in Ada County
is forecasted to reach 1,011,200 and Canyon County population grows to 437,800. Ada and
Canyon county High Scenario populations in the year 2045 are projected to be 157,800 (12.2
percent) higher than in the Base Scenario. The accelerated population growth in the High
Scenario also increases the projected number of households in the state. In the High Scenario
Forecast the counties along Intermountain Gas Company’s Idaho Falls Lateral are projected to
attain a population of 628,400, and a total of 205,600 households. These projections represent
an increase in the 2045 population of 99,000, and an increase of 26,300 households when
compared to the Base Scenario Forecast. Bonneville County is forecasted to account for nearly
46.0 percent of the population gains along the Idaho Falls Lateral with Bannock, Madison, and
Jefferson counties accounting for 21.0 percent, 20.0 percent, and 11.0 percent respectively of
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Residential & Commercial Customer Growth Forecast

the area’s population gains in the High Scenario. High Scenario population gains in Butte,
Fremont, and Power counties are forecasted to account for only about 2.0 percent of the area’s
population gains.
In the High Growth Scenario of the ‘20 Forecast it is assumed that Idaho will be a modestly more
attractive environment for manufacturing firms. Therefore, manufacturing employment in Idaho
continues a recovery that started after the end of the 2008 Great Recession. It is forecasted in
the High Scenario of the Winter 2020 Economic Forecast that manufacturing employment in
Idaho will reach 97,600 in the year 2045. This is 5,500 jobs higher (5.9% higher) than projected
employment in the Base Scenario forecast.
It is assumed in the High Scenario that Idaho’s Food Processing industry will shed a lower number
of jobs in its vegetable processing facilities across the state. Furthermore, it is assumed that Idaho
will continue to attract new, higher value-added, food processing firms to the State. And as was
the case in the Base Scenario Forecast there is no expectation for the location of a new electronics
manufacturing plant in the State. It is expected that Idaho’s manufacturing employment
associated with the Lumber and Wood Products, Paper Products, and Chemical Products
manufacturing will remain relatively constant and will not be a significant factor driving future
manufacturing employment growth. Lastly, it is assumed that manufacturing employment in the
State’s Transportation Equipment industry will not directly benefit from the High Scenario
forecast's stronger economic growth. Growth in Idaho’s Transportation Equipment
manufacturing may only occur without an in-migration of those firms, relatively small in scale,
relocating to Idaho. However, it is assumed that the state will gain manufacturing employment
due to an in-migration of smaller firms in the Machinery and Equipment and Fabricated Metals
manufacturing industries.
The Service Industries are forecasted to provide most of the employment gains in the High
Scenario Forecast. At the year 2045, it is forecasted in the High Scenario that employment in the
Professional and Business Services industry will be nearly 32,000 (14.4 percent) higher than the
Base Scenario Forecast. Likewise, the Education and Health Services and the Leisure and
Hospitality Services industries which are forecasted to have their High Scenario employment in
the State reach levels that are 39,300 (14.1 percent) and 21,200 (14.7 percent) higher than in the
Base Scenario Forecast. Ada and Canyon counties are projected to account for nearly 60.0
percent of the additional service industry employment projected in the High Scenario Forecast.
Kootenai and Bonner counties in Northern Idaho are projected to account for nearly 13,000 jobs
(14.0 percent) of the additional service industry in the High Scenario Forecast.

The Low Growth Economic Scenario
By the year 2045 it is projected in the Low Scenario of the ‘20 Forecast that population in Idaho
will be 2,558,500. The Low Scenario forecast of population in the year 2045 is 466,200 lower
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Residential & Commercial Customer Growth Forecast

(-15.4 percent) than the 2045 Base Scenario Forecast of population. The 2045 forecasted number
of households in Idaho is 182,800 lower (-17.5 percent) in the Low Scenario Forecast.
In the Low Case Economic Forecast, it is assumed that the strong population in-migration to Idaho
that has occurred over the last two decades will not accelerate in the future. A net migration of
persons and business out of California to other states will be increasingly captured by other states
in the West and Southwest. This represents a reversion to the pattern seen from 1990 through
2000 where Nevada, and then Arizona, and lastly Utah captured most of the economic growth
attributable to migration out of California.
The capture of this migration by other states will cause Idaho to grow at a slower pace and will
make the state less attractive to a job-seeking population that would otherwise migrate to Idaho.
Adding to this phenomenon the loss of a major employer or a substantial downturn in a major
industry in the state and a low economic growth could be a reality for Idaho. For example, a
closure of Micron’s operations in Idaho or a corporate takeover of an Idaho company could lead
to the relocation of a corporate headquarters from Idaho. And lastly as an example, a substantial
downturn in the dairy industry could lead to a reduction of dairy herds in Idaho, and thereafter a
cutback or closure of dairy processing facilities in Idaho.
In the Low Scenario of the ‘20 Forecast total nonagricultural employment in Idaho is projected to
reach 1,523,100 in the year 2045. This is 13.0 percent, or 198,800 jobs, lower than Idaho’s
forecasted 2045 nonagricultural employment projected in the Base Scenario Forecast.
Idaho’s manufacturing employment in the Low Scenario Forecast is projected to reach a 92,200
in the year 2045 which is 8,800 jobs (9.6 percent less than the 2045 Base Scenario Forecast of
Idaho’s manufacturing employment). In the Low Scenario forecast the State's loss of jobs in the
Food Processing industry accelerates and nearly 1,500 additional jobs are lost over the years of
2020 to 2045. The most likely scenario is that the potato processing plants in Southern Idaho
would experience the bulk of these job losses. It is assumed in the Low Scenario that one or more
potato processing plants would be substantially cut back or even closed. A further assumption in
the Low Scenario Forecast is that the sugar processing plants in Southern Idaho would also feel
increased pressure from competition and would find it necessary to close one of the sugar
processing plants in either Nampa, Paul, or Twin Falls, Idaho. The dairy industry and its associated
food processing plants would reach a point where no further capacity could be added due to
increased population and environmental pressures.
Employment losses in Idaho's Lumber and Wood Products manufacturing industry are assumed
to accelerate in the Low Scenario. In this scenario the brunt of these additional losses would be
felt in those portions of the wood products industry that could be increasingly vulnerable to low
cost foreign produced products - the Wood Grain Molding plants in Fruitland and Nampa, Idaho.

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Residential & Commercial Customer Growth Forecast

Idaho's Electronics and Machinery manufacturing industries would experience further job losses
over the forecast period. Employment in Stone, Clay, and Glass Products and Fabricated Metal
Products manufacturing are both projected to be at lower levels of total employment than in the
Base Scenario of the economic forecast.
Transportation, Trade, and Utilities employment in the Low Scenario Forecast is projected to
have nearly 9,600 fewer jobs (-4.4 percent) in the year 2045 than in the Base Scenario forecast.
The impact of slower economic growth in the state inherent in the Low Scenario Forecast
produces lower levels of demand for transportation services and for the buying opportunities of
additional retail stores.
The Low Scenario forecast of statewide 2045 employment in the Finance, Insurance, and Real
Estate and the Information sectors of the economy are projected to be nearly 15,900 (-14.5
percent) lower than expected in the Base Scenario Forecast by the year 2040. Again, the
difference is largely due to the lower levels of population and household growth inherent in the
Low Case Scenario.
The outlook for Service industry employment in the Low Scenario Forecast assumes that
employment growth in the Service sector slows proportionate to the projected slower growth in
population and households statewide. In total, employment in the Professional and Business
Services, Educational and Health Services, and Leisure and Hospitality Services industries are
projected in the Low Scenario Forecast to attain a 2045 level of employment of 525,700, which
is 120,160 lower (- 18.6 percent) than in the Base Scenario Forecast.
Future Government employment in the Low Scenario is projected to be 11.7 percent (26,600
jobs) lower than the Base Scenario forecast by the year 2045. As previously mentioned for other
industries the reason for projected lower levels of Government employment in the Low Scenario
forecast are the slower rates of population and household growth in the Low Scenario Forecast.
It is assumed in the Low Scenario Forecast that the number of assigned military personnel at
Mountain Home Airforce Base will remain at levels that are similar to those at the present time.
Forecast Households
As previously stated, the basis for the customer growth forecast relies on the annual variance, or
change, in households from year to year, within the counties in which Intermountain operates.
The graph below (Figure 6) provides a visual depiction of the variance in household growth for
high growth, base case and low growth scenarios for the counties which Intermountain Gas
Company serves.

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Residential & Commercial Customer Growth Forecast

Figure 6: Annual Additional Households Forecast

A comparison of the base case household growth, between the common years in the 2019 and
2021 IRPs, is depicted below (Figure 7).

Figure 7: Additional Households Forecast - Base Case: 2019 IRP vs 2021 IRP

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Residential & Commercial Customer Growth Forecast

Market Share Rates
To determine the potential market share of new households, Intermountain takes a historical
look at its past performance in regard to the ratio of customer acquisitions per building permit
issued; then applies that factor to future estimates of household growth across its 5 Operations
Districts.
Intermountain develops market penetration rates by way of county building permit reports
which the Company’s Energy Service personnel use in prospecting for new construction
customers. These reports are made available through Construction Monitor, a nationwide
building permit monitoring service to which Intermountain subscribes. To derive the penetration
rate for this IRP, a query of street addresses of all residential permits issued from 2016- 2020 was
compared to a query of all active residential service points addresses in Intermountain’s
customer billing system. The results were then scrubbed for false negatives due to addressing
variations between the data sets. i.e.; Rd. vs Road, St. vs Street or compass designations N, S, E,
W. Once this task was completed, the results were sorted by District. This methodology is
congruent with the derivation of Household growth figures by county. It is assumed that some
permits are issued outside of the Company’s reachable service territory, but within the counties.
This penetration rate is then applied, by District, to the Household growth figures to derive an
estimate of future customer acquisition. See Figure 8 below for market penetration rates by
district.

Figure 8: Market Penetration Rate - By District

The following graph (Figure 9) illustrates the relationship between the three economic scenarios
for the annual residential new construction growth forecast for 2021 – 2026:

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Residential & Commercial Customer Growth Forecast

Figure 9: Residential New Construction Growth

The following graph (Figure 10) shows the difference in base case residential new construction
customer growth between the 2019 and 2021 IRP forecast years common to both studies:

Figure 10: Annual Residential New Construction Growth - Base Case: 2019 IRP vs 2021 IRP

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Residential & Commercial Customer Growth Forecast

Conversion Rates
The conversion market represents another source of customer growth for the Company.
Intermountain acquires these customers when homeowners replace an electric, oil, coal, wood,
or other alternate fuel source furnace/water heater with a natural gas unit. Intermountain
forecasts these customer additions by applying regional conversion rates based on historical data
and future expectations. The following table shows, by region, the assumed conversion rates
used in the IRP. These rates represent the percentage of new customer additions which will be
conversions. The calculated conversion forecast is then added to the new construction forecast
to derive the total residential growth forecast.
The table below illustrates the conversion rates used in the 2021 and 2019 IRPs.
Table 3: Regional Conversion Rate
Regional Conversion Rate
2021 2019
EASTERN
REGION 5% 7%
CENTRAL
DIVISION 12% 20%
WESTERN
REGION 15% 19%

The following graph (Figure 11) illustrates the relationship between the three economic scenarios
for the annual residential conversion growth forecast for 2021 – 2026:

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Residential & Commercial Customer Growth Forecast

Figure 11: Annual Residential Conversion Growth

The following graph (Figure 12) shows the difference in the base case forecast of residential
conversion customer growth between the 2019 and 2021 IRP forecast years common to both
studies:

Figure 12: Annual Residential Conversion Growth – Base Case: 2019 IRP vs. 2021 IRP

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Residential & Commercial Customer Growth Forecast

Commercial Customer Forecast
The following graph (Figure 13) shows the forecast annual additional commercial customers
based on the low growth, base case and high growth scenarios developed using the methodology
explained previously.

Figure 13: Additional Commercial Customers
The following graph (Figure 14) shows the difference in base case commercial customer growth
between the 2019 and 2021 IRP forecast years common to both studies:

Figure 14: Annual Additional Commercial Customers – Base Case: 2019 IRP vs. 2021 IRP

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Heating Degree Days & Design Weather

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.

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 2020. 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.

Design Degree Days
Design Degree Days represent the coldest temperatures that can be expected to occur for a given
day. Design Degree Days are a critical input for modelling the level of customer demand that may
occur during extreme cold or “peak” weather events. For IRP load forecasting purposes,
Intermountain makes use of design weather assumptions.
Intermountain’s design year is based on the premise that the coldest weather experienced for
any month, season, or year could occur again. The Company reviewed NOAA temperature data
over the period of record and found the coldest twelve consecutive months in Intermountain’s
service territory to be the 1984/1985 heating season (October 1984 through September 1985).
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Heating Degree Days & Design Weather

That year, with certain modifications discussed below, represents the base year for design
weather.

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 over using the coldest observed daily average temperature,
because exceedance probabilities corresponding to values obtained from the probability
distributions are known. This enables IGC to choose a design temperature, from among a range
of values, which corresponds to an exceedance probability that IGC considers appropriate for the
intended use”.
Intermountain used Dr. Qualls’ exceedance probability results to review the data associated with
both the 50 and 100 year probability events. After careful consideration of the data,
Intermountain determined that the company-wide 50 year probability event, which was a 78
degree day, would be appropriate to use in the design weather model.
Base Year Design Weather
To create a design weather year from the base year, a few adjustments were made to the base
design year. First, since the coldest month of the last thirty years was December 1985, the
weather profile for December 1985 replaced the January 1985 data in the base design year. For
planning purposes, the aforementioned peak day event was placed on January 15th.
To model the days surrounding the peak event, Dr. Qualls suggested calculating a 5-day moving
average of the temperatures for the past thirty-year period to select the 5 coldest consecutive
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
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Heating Degree Days & Design Weather

three days following the peak day, were replaced with the 4 cold days surrounding the December
1990 peak day.
While taking a closer look at the heating degree days used for the Load Demand Curves (LDCs),
the Company noticed that the design HDDs in some of the shoulder and summer months were
lower than the normal weather HDDs for those months. This occurred because, while the 1985
heating year was overall the coldest on record, the shoulder months were in some cases warmer
than normal. Manipulating the shoulder and summer month design weather to make it colder
would add degree days to the already coldest year on record, creating an unnecessary layer of
added degree days. Intermountain decided not to adjust the summer and shoulder months of
the design year.
After design modifications were completed, the total design HDD curve assumed a bell-shaped
curve with a peak at mid-January (see Figure 15 below). This curve provides a robust projection
of the extreme temperatures that can occur in Intermountain’s service territory.

Figure 15: Design Heating Degree Days

The resulting Normal, Base Year (1985), and Design Year degree days by month are outlined in
Table 4 below:
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Heating Degree Days & Design Weather

Table 4: Monthly Heating Degree Days

Area Specific Degree Days
As noted earlier in this IRP, Intermountain has identified certain areas of interest. These are areas
Intermountain carefully manages to ensure adequate delivery capabilities either due to a unique
geographic location, customer growth, or both.
The temperatures in these areas can be quite different from each other and from the total
company. For example, the temperatures experienced in Idaho Falls or Sun Valley can be
significantly different from those experienced in Boise or Pocatello. Intermountain continues to
work on improving its capability to uniquely forecast loads for these distinct areas. A key driver
to these area specific load forecasts is area specific heating degree days.
Intermountain has developed Normal and Design Degree Days for each of the areas of interest.
The methods employed to calculate the Normal and Design Degree Days for each AOI mirrors the
methods used to calculate Total Company Normal and Design Degree Days.

Actual Heating Year
1985
Weighted Normal
(30 Year Rolling)
Design Year
Monthly Heating Degree Days
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Usage Per Customer

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.

Methodology
Intermountain Gas utilizes a Customer Management Module (CMM) software product, provided
by DNV (formerly known as 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. DNV operates in
over 100 countries and specializes in the maritime, oil, gas and energy industries. Its array of
pipeline software has been a powerful engineering tool within the United States for decades,
used by natural gas companies such as Avista, Pacific Gas and Electric, Dominion, Northwest
Natural and Williams. The CMM product branch is used in correlation with Synergi Gas, a
hydraulic modeling software program discussed in the Distribution System Modeling section
beginning on page 92 of this IRP.
The first step in operating CMM is extensive data gathering from the Company’s Customer
Information System (CIS). The CIS 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 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.
The Company used approximately three years of data from its CIS. 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.
Usage per Customer by Geographic Area
The Company recognizes that there could be significant differences in the way its customers use
natural gas throughout its geographically and economically diverse service territory. Being
sensitive to areas that may require capital improvements to keep pace with demand growth,
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Usage Per Customer

Intermountain separated customers into distinct AOIs, and then determined specific usages per
customer for each.
In order to refine usage per customer to an AOI, customer addresses were used to create groups
by town, and towns were combined with their related AOI. Central Ada and State Street AOI’s
share towns in their respective territories, so a combined geographic area was created to
calculate their shared usage per customer. Towns on the Sun Valley Lateral were combined to
calculate a single usage per customer, but for flow analysis purposes it was found that more
granular customer breakdowns are required, and the usage per customer was represented
separately for each town due to the range of usages and geographic sensitivity along the lateral.
The same Sun Valley Lateral methodology was applied to the Idaho Falls Lateral.

Model Validation
To check the usage per customer Intermountain validates the models for a specific temperature
event. Following construction of the model, Intermountain worked with DNV to validate
regulator pressures, source flows, and temperature information for verification points across the
system. DNV made a peak hour factor and heating degree day adjustment to allow for accurate
load comparison. This check verified that CMM-predicted loads align with actual supply system
flow. Comparing the model results to actual pressures and flows allows the Company to validate
the model and have confidence that the usage per customer from CMM is accurate to
temperatures experienced in each geographic area.
In a separate validation check, Intermountain compared customer usage predicted in CMM to
actual customer usage on its fixed network. Intermountain pulled available fixed network data
for a temperature event and compared the customer usage for a small number of meters that
have fixed network capability and found that the usage per customer was reasonable for the
current quality of its fixed network data. Currently Intermountain only has a limited number of
meters on fixed network and the fixed network system has limitations on gas correction factors.
As discussed on page 79, the Company is in the process of implementing a fixed network metering
system. As the fixed network system becomes fully deployed, the Company will be able to utilize
the gathered data to further refine its usage per customer validation process.

Conclusion
The process described above is an effective methodology for calculating usage per customer. As
discussed in the Load Demand Curves Section of this IRP, the usage per customer data produced
from the process described above is a critical component in the development of the Company’s
load demand curves. The usage per customer data is applied to the customer forecast and design
weather to create daily core market load projections for the IRP period.
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Large Volume Customer Forecast

Large Volume Customer Forecast

Introduction
The Large Volume (LV) customer group is comprised of approximately 140 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 50% of Intermountain’s annual throughput and 28% of the projected 2021
design Base Case peak day. Nearly 97% of 2020 LV throughput reflects distribution system-only
transportation tariffs where customer-owned natural gas supplies are delivered to
Intermountain’s various Citygate stations for ultimate redelivery to the customers’ facilities.
Because the LV customers’ volumes account for such a large part of Intermountain’s overall
throughput, the method of forecasting these customers’ overall usage is an important part of the
IRP. These customers’ growth and usage patterns differ significantly from the residential and
commercial customer groups in two significant ways. First, the LV customers’ gas usage pattern
as a whole is not nearly as weather sensitive as the core market customers, meaning that
forecasting their volumes using standard regression techniques based on projected weather does
not provide statistically significant results. Secondly, the total LV customer count is so few that it
falls below the number required to provide an adequate statistical population/sample size.
Therefore, Intermountain has developed and utilizes an alternate, but very accurate method of
forecasting based on historical usage, economic trends, and direct input from these Large Volume
customers. The chart below (Figure 16) shows a comparison of total actual LV therm use against
forecast therm use from the 2019 IRP for the years 2019 – 2021.
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Large Volume Customer Forecast

Figure 16: LV Therms - 2019 IRP Forecast vs Actuals
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 3 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.
An important source of forecasting information comes from the customers themselves. Prior to
each IRP cycle, Intermountain sends out a survey to each customer requesting information
relating to changes in usage patterns. Such a survey was sent out in November 2020. As shown
on page 46 (Figure 17), the survey form included a cover letter explaining the need for and the
use of the requested information with the assurance that all responses would remain
confidential. The surveys provided each customer’s historical peak day and monthly usage for
the two years ending September 2019 and 2020 . See Figure 18 on page 47 for a sample of the
survey.
The historical information was provided to help LV customer’s management, engineers, and/or
operations personnel identify how much and when recent natural gas usage patterns were likely
to change going forward. Specifically, the survey requested projections of changes in natural gas
consumption related to plant expansion, equipment modification or replacement and
anticipated changes in product demand and production cycles through 2026.
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
2019 2020 2021
00
0
'
s

o
f

T
h
e
r
m
s
2019 IRP LV Therm Forecast vs Actual
Actual/CE 2019 IRP Forecast
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Large Volume Customer Forecast

Additionally, each customer was provided an opportunity to give recommendations for
additional service options or other feedback. About 35% of customers returned completed
surveys and analysis of the returned surveys was completed by early March 2021. Where
customers predicted material changes in future therm use, the Company adjusted the annual
2022-26 base year data.

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 the economic forecast provided by John Church (see Exhibit 2, Section A), other
economic development organizations and alternate economic forecasts/assumptions were
utilized to develop the High Growth and Low Growth scenarios. For ease of analysis, the 140
existing and up to 14 projected new customers (per the High Growth scenario) were combined
into six (6) homogeneous market segments:

2021 Customers by Market Segment:
• 18 potato processors
• 44 other food processors including sugar, milk, beef, and seed companies
• 3 chemical and fertilizer companies
• 31 light manufacturing companies including electronics, paper, and asphalt companies
• 32 schools, hospitals, and other weather sensitive customers
• 12 “other” companies including transportation-related businesses

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. The IRP will use the
term contract demand (CD) when referencing both MDFQ and MDQ. For this IRP, Intermountain
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utilized LV customer CD’s as they existed at January 1, 2021 for the beginning point for Base Case
CD’s.
While many of LV customers’ surveys predict their annual usage requirements will likely grow
through 2026, 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.

“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 CD’s 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 it makes sense to use the customer CD as the
daily requirement, as it reflects the known peak day obligation for every customer and each 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 need 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
meaningless to Intermountain.

System Reliability
It is important to note that before adding new firm load, engineers tests the system via its
modeling system to determine whether or not the Company could serve that added load under
design weather peak day loads before proceeding. That 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
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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.

General Assumptions
All current customers were assumed to remain on their current tariff and all forecast scenarios
used the 2020 operating budget as a starting point. The IRP also calculated LV therm use and
MDFQ by AOI so that each geographic area of concern can be accurately modeled.

Base Case Scenario Summary
The Base Case was compiled using historical usage and surveys 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 5 below. The rate of projected annualized growth remains strong compared to the last
IRP largely due to growth in Other Food, Manufacturing, and Institutional customers.
Table 5: Large Volume Therm Forecast - Base Case Scenario

A. The Potato Processors group is forecast to slightly decline over the forecast period.
Demand for potato products is projected to soften as consumer tastes change although
inventory remains adequate. No new plants are assumed in the forecast while recent
plant expansions have not increased gas usage as expected. Most of the plants in this
group are looking for ways to lower the overall cost of production, conserve resources
and maximize efficiencies leading to the projected decline in projected usage.

B. The Other Food Processing group is projected to see fairly strong growth over the forecast
period. The growth is largely due to strong growth in sugar and frozen food production.

Rate of
2021 2022 2023 2024 2025 2026 Growth
Potato (A)115,563 108,793 112,927 113,804 112,754 112,625 -0.5%
Other Food (B)109,595 115,025 116,296 116,453 116,513 116,576 1.2%
Meat, Dairy and Ag (C) 50,409 55,208 55,558 59,213 59,718 59,728 3.5%
Chemical/Fertilizer (D)33,272 31,150 32,150 32,572 32,572 32,572 -0.4%
Manufacturing (E)23,428 26,033 26,634 27,498 27,513 27,529 3.3%
Institutional (F)24,835 26,475 26,763 26,831 26,831 26,831 1.6%
Other (G)17,708 10,464 15,444 19,262 19,298 19,029 1.4%
Total Base Case 374,810 373,148 385,772 395,633 395,199 394,890 1.0%
Large Volume Therm Forecast - Base Case Scenario by Market Segment
(Thousands of Therms)
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Large Volume Customer Forecast

C. The Meat, Dairy and Ag segment is projected to see very strong growth which largely
reflects several new meat plants and at least one new dairy processing plant to come
online by 2024.

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

E. The Manufacturing group is expected to see strong growth. Intermountain expects to see
increases in electronics manufacturing and also expects to see growth in businesses
engaged in new construction.

F. The Institutional group is projected to grow at 1.6% a year due to a return to normal
weather, to existing hospitals expanding facilities, and to new hospitals that have recently
been built or new facilities that will be built in the coming years.

G. The usage in the Other group is projected to see some reasonably strong growth largely
due to customers using more natural gas as a transportation fuel. The Company assumes
that renewable fuel production customers will not be slowed by the pandemic or due to
increased calls for electrification.

High Growth Forecast Summary
The High Growth forecast incorporates usage data directly from the survey with adjustments for
additional growth that would occur if the economy continues to recover and expand. The
scenario assumes very competitive natural gas prices compared to other alternatives and that
the economy fully recovers from the downswing due to COVID-19. Projected sales in year 2022
of the High Growth forecast of 378.7 million therms is approximately 1.5% above Base Case. By
2026 the High Growth scenario’s annual sales grow to 428.4 million therms an increase of 33.5
million therms (8.5%) over 2026 Base Case. The following table summarizes the High Growth
changes over the forecast period:

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Table 6: Large Volume Therm Forecast - High Growth Scenario

A. Potato production is up from the 2019 IRP projections and future growth is strong. This
scenario shows the processors consistently growing and includes an assumption of at
least one new customer. 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 and at least two new dairy processors come
online during the forecast period.

D. The Chemical/Fertilizer group’s gas usage is anticipated to increase over the five-year
period due to growth in phosphate production.

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

F. The institutional group is expected to grow 2.2% over the five-year period as some growth
is projected in a few of the larger universities and several hospitals.

G. Growth is expected to be strong in the Other segment as the effects of the COVID-19
pandemic on renewable fuels and CNG customers should dissipate.

Rate of
2021 2022 2023 2024 2025 2026 Growth
Potato (A)115,563 109,393 117,005 118,757 120,728 122,754 1.2%
Other Food (B)109,595 115,125 122,085 123,142 123,902 124,216 2.5%
Meat, Dairy and Ag (C) 50,409 55,268 60,787 68,768 70,078 70,293 6.9%
Chemical/Fertilizer (D)33,272 33,913 35,663 36,084 36,084 36,084 1.6%
Manufacturing (E)23,428 26,033 26,769 28,013 28,093 28,124 3.7%
Institutional (F)24,835 26,475 26,886 27,099 27,606 27,656 2.2%
Other (G)17,708 12,538 16,518 19,527 19,564 19,295 1.7%
Total Base Case 374,810 378,745 405,713 421,390 426,055 428,422 2.7%
Large Volume Therm Forecast - High Growth Scenario by Market Segment
(Thousands of Therms)
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Large Volume Customer Forecast

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 the pandemic. It is also assumed that natural gas prices will be less
competitive and other renewable sources begin to increase market share vis-à-vis natural gas.
With those assumptions, the agricultural part of the economy will be flat with very little growth
in sales and production. Declines are expected in Potato Processing and the Other segments is
expected to fall as the renewable fuels market declines and CNG markets are replaced by EV’s.
Projected sales in year 2022 of the Low Growth Scenario are approximately 1% below the Base
Case but by 2026 are projected sales are 24.3 million therms (6.2%) under Base Case. The
following table summarizes the Low Growth changes over the forecast period:
Table 7: 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.

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 decline in gas usage as demand
for chemicals decrease.

E. The Manufacturing group is also projected to increase over the period by 1.0% reflecting
some strength in the high tech/electronics and building markets.
Rate of
2021 2022 2023 2024 2025 2026 Growth
Potato (A)115,563 108,793 110,429 110,858 109,708 109,678 -1.0%
Other Food (B)109,595 114,743 114,814 114,871 114,931 114,995 1.0%
Meat, Dairy and Ag (C) 50,409 55,008 58,358 58,613 58,618 58,628 3.1%
Chemical/Fertilizer (D)33,272 31,850 31,600 32,272 32,272 32,272 -0.6%
Manufacturing (E)23,428 25,260 24,998 24,678 24,678 24,678 1.0%
Institutional (F)24,835 24,704 24,682 24,562 24,247 24,112 -0.6%
Other (G)17,708 9,961 7,014 6,775 6,617 6,196 -18.9%
Total Base Case 374,810 370,319 371,895 372,629 371,071 370,559 -0.2%
Large Volume Therm Forecast - Low Growth Scenario by Market Segment
(Thousands of Therms)
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Large Volume Customer Forecast

F. The institutional group is projected to also show slowing growth that would lead to a small
decrease in annual gas use.

G. At least one very large renewable 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.

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Large Volume Customer Forecast

LARGE VOLUME CUSTOMER SURVEY – COVER LETTER

Figure 17: Large Volume Customer Survey Cover Letter
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Large Volume Customer Forecast

Figure 18: Large Volume Customer Survey Questions
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Supply & Delivery Resources Overview

Supply & Delivery Resources

Supply & Delivery Resources Overview

Once future load requirements have been forecasted, currently available supply and delivery
resources are matched with demand to identify system deficits. Essential components
considered when reviewing supply and delivery resources include identifying currently available
supply resources, delivery capacity, and other resources that can offset demand such as energy
efficiency programs or large volume customers with alternative fuel sources.
Supply and deliverability are considered by AOI to identify system constraints that result from
forecasted demand. By comparing demand versus capacity for each AOI, the Company is better
able to select capacity constraint solutions that consider cost effectiveness, operations and
maintenance impacts, project viability, and future growth.
After analyzing resource requirements for each AOI, the data is aggregated to provide a total
company perspective. Supply and delivery resources that are currently available are compared
to the six total company demand scenarios that were established in the demand forecast. In the
Load Demand Curves Section, beginning on page 118, demand and capacity are compared to
clearly identify deficits. Alternative solutions for how the deliverability deficits will be resolved
are considered in the Optimization and Planning Results sections of this Integrated Resource
Plan.

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Traditional Supply Resources

Traditional Supply Resources

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 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.

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.

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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.

Gas Supply Resource Options
Over the past decade, 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 19 below).

Figure 19: 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 20 below for consumption by
sector, 2000-2050.
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Traditional Supply Resources

Figure 20: Natural Gas Consumption by Sector
Source: EIA AEO2021

Improved technologies for finding and producing nonconventional gas supplies have led to
dramatic increases in gas supplies. Figure 21 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 21: Shale Gas Production Trend
Source: EIA AEO2021

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Traditional Supply Resources

While natural gas prices continue to exhibit volatility from national, global, and regional
perspectives, the laws of supply and demand clearly govern the availability and pricing of natural
gas. Recent history shows that periods of growing demand tends to drive prices up which in turn
generally results in consumers seeking to lower consumption. At the same time, producers
typically increase investment in activities that will further enhance production. Thus, falling
demand coupled with increasing supplies tends to swing prices lower. This in turn leads to falling
supplies and increased demand which begins the cycle anew (see Figure 21 for shifting demand).
Finding equilibrium in the market has been challenging for all market participants but at the end
of the day, the competitive market clearly works; the challenge is avoiding huge swings that result
in either demand destruction or financial distress in the exploration and production business.
Driven by technological breakthroughs in unconventional gas production, major increases in
North American natural gas reserves and production have led to supply growth significantly
outgaining forecasts in recent years. Thus, natural gas producers have sought new and additional
sources of demand for the newfound volumes. The abundant supply of natural gas discussed
above has resulted in the United States becoming a net exporter of liquefied natural gas (LNG)
versus being a net importer several years ago. The currently operational LNG export facilities in
the United States together with additional new facilities on the drawing board will result in a
significant new market for the incremental gas supplies being developed and produced.
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 22 below 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 2020 9, 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 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.”

9 https://www.eia.gov/outlooks/aeo/pdf/AEO_Narrative_2021.pdf
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Figure 22: US Lower 48 States Shale Plays
Source: Energy Information Administration based on data from various published studies.

Supply Regions
As previously stated, Intermountain's natural gas supplies are obtained primarily from the WCSB
and the Rockies. Access to those abundant supplies is completely dependent upon the amount
of firm transportation capacity held on the applicable pipelines for delivering such gas to
Intermountain’s service territory. Transportation capacity is so important that a discussion of the
Company’s purchases of natural gas cannot be fully explored without also addressing pipeline
capacity. On average, Intermountain currently purchases approximately 79% of its gas supplies
from the WCSB and the remainder from the Rockies. However, due to certain flexibility in
Intermountain’s firm transportation portfolio, it is afforded the opportunity to procure some
portion of its annual needs from supply basins which may offer lower cost gas supplies in the
future.
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Traditional Supply Resources

Alberta
Alberta supplies are delivered to Intermountain via two Canadian pipelines (TransCanada Energy
via NOVA Gas Transmission Ltd. (NOVA) and Foothills Pipe Lines Ltd. (Foothills)) and two U.S.
pipelines (Gas Transmission Northwest (GTN) and Williams Northwest Pipeline (NWP)) as seen
below in Figure 23.

Figure 23: 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.

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
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Enbridge (Westcoast) to an interconnect with NWP near Sumas, WA. Historically, much of the
provincial supply had been somewhat captive to the region due to the lack of alternative pipeline
options into eastern Canada or the midwestern U.S. However, pipeline expansions into these
regions have eliminated that bottleneck. Although these supplies must be transported long
distances in Canada and over an international border, there have historically been few political or
operational constraints to impede ultimate delivery to Intermountain's citygates. An exception
to pipeline constraints occurred during the winter of 2018 when Enbridge had a major disruption
from a pipeline rupture that occurred on October 9, 2018. The ensuing winter months saw a
reduction in capacity in British Columbia gas supplies to be delivered at Sumas due to the incident
and pipeline integrity testing required by the Canada Energy Regulator 10 in Canada to ensure
safe and reliable pipeline conditions. Those interruptions along with a cold and long winter had
a significant impact on pricing. However, due to the predominance of Intermountain’s supplies
coming from Alberta and being delivered via GTN at Stanfield, coupled with Intermountain’s
ability to utilize its liquefied natural gas storage contracts on NWP’s system, it was able to mitigate
the impact to its customers of the dramatic short-term price increases.

Rockies
Rockies supply has been the second largest source of supply for Intermountain because of the
ever-growing reserves and production from the region coupled with firm pipeline capacity
available to Intermountain. Additionally, Rockies supplies have been readily available and highly
reliable. Historically, pipeline capacity to move Rockies supplies out of the region has been
limited, which has forced producers to compete to sell their supplies to markets with firm
pipeline takeaway capacity. Several pipeline expansions out of the Rockies have greatly
minimized or eliminated most of the capacity bottlenecks, so these supplies can now more easily
move to higher priced markets found in the Midwest, East or in California. Consequently, even
though growth in Rockies reserves and production continues at a rapid pace reflecting increased
success in finding tight sand, coal seam and shale gas, the more efficient pipeline system has
largely eliminated the price advantage that Pacific Northwest markets had enjoyed.
While Intermountain’s firm transportation portfolio does provide for accessing Rockies gas
supplies, as discussed above, Intermountain has 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.

10 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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Export LNG
Growth in North American natural gas supplies (see Shale Gas above) has eliminated discussion
about LNG import facilities. Because LNG is traded on the global market, where prices are
typically tied to oil, U.S. produced LNG is very competitive. LNG exports now play a role in the
overall supply portfolio of U.S. supply, with several new LNG export facilities proposed or in
production. As seen in Figure 24 below, the U.S. is now a net exporter of natural gas in large part
due to LNG.

Figure 24: Natural Gas Trade
Source: EIA AEO2021

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.

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Intermountain builds its supply portfolio on a base of firm, long-term gas supply contracts but
includes all the types of gas supplies as described below:

1. Long-term: gas that is contracted for a period of over one year.
2. Short-term: gas that is often contracted for one month at a time.
3. Spot: gas that is not under a long-term contract; it is generally purchased in the short-
term on a day ahead basis for day gas and during bid week prior to the beginning of the
month for monthly spot gas.
4. Winter Baseload: gas 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.

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 25.

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Figure 25: Intermountain Price Forecast as of 04/22/2021

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 139), 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 26 below). Intermountain also leases capacity from Dominion Energy Pipeline’s Clay
Basin underground storage field in Wyoming, and operates its own LNG facility located in Nampa,
ID. Additionally, Intermountain owns a satellite LNG facility in Rexburg, ID. The Rexburg facility is
supplied with LNG from the Nampa LNG facility.

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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.

Liquefied Storage
Liquefied storage facilities make use of a process that super cools and liquefies gaseous methane
under pressure until it reaches approximately minus 260°F. LNG occupies only one-six-hundredth
the volume compared to its gaseous state, so it is an efficient method for storing peak
requirements. LNG is also non-toxic; it is non-corrosive and will only burn when vaporized to a 5-
15% concentration with air. Because of the characteristics of liquid, its natural propensity to boil-
off and the enormous amount of energy stored, LNG is normally stored in man-made steel tanks.

Figure 26: Intermountain Storage Facilities
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Liquefying natural gas is, relatively-speaking, a time-consuming process, the compression and
storage equipment is costly, and liquefaction requires large amounts of added energy. It typically
requires as much as one unit of natural gas burned as fuel for every three to four units liquefied.
Also, a full liquefaction cycle may take five to six months to complete. Because of the high cost
and length of time involved in filling a typical LNG facility, they are usually cycled only once per
year and are reserved for peaking purposes. This makes the unit cost of the gas withdrawn
somewhat expensive when compared to other options.
Vaporization, or the process of changing the liquid back into the gaseous state, on the other hand,
is a very efficient process. Under typical atmospheric and temperature conditions, the natural
state of methane is gaseous and lighter than air as opposed to the dense state in its liquid form.
Consequently, vaporization requires little energy and can happen very quickly. Vaporization of
LNG is usually accomplished by utilizing pressure differentials by opening and closing valves in
concert with the use of some hot-water bath units. The high-pressure LNG is vaporized as it is
warmed and is then allowed to push itself into the lower pressure distribution system. Potential
LNG daily withdrawal rates are normally large and, as opposed to the long liquefaction cycle, a
typical full withdrawal cycle may last 10 days or less at full rate. Because of the cost and cycle
characteristics, LNG withdrawals are typically reserved for needle peaking during very cold
weather events or for system integrity events.
Neither of the two LNG facilities utilized by Intermountain require the use of year-round
transportation capacity for delivery of withdrawals to Intermountain’s customers. The Plymouth
facility is bundled with redelivery capacity for delivery to Intermountain and the Nampa and
Rexburg LNG tank withdrawals go directly into the Company’s distribution system. The IRP
assumes liquid storage will serve as a needle peak supply.

Underground Storage
This type of facility is typically found in naturally occurring underground reservoirs or aquifers
(e.g. depleted gas formations, salt domes, etc.) or sometimes in man-made caverns or mine
shafts. These facilities typically require less hardware compared to LNG projects and are usually
less expensive to build and operate than liquefaction storage facilities. In addition, commodity
costs of injections and withdrawals are usually minimal by comparison. The lower costs allow for
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
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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 8 below outlines the Company’s storage resources for this IRP.

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Table 8: 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.

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.

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
Daily Withdrawal (Dth) Daily Injection (Dth) Seasonal % of 2021 Redelivery Facility Capacity Max Vol Peak Max Vol # of Days Capacity
Nampa 600,000 60,000 13% 3,500 166 None
Plymouth 1,475,135 155,175 33% 12,500 213 TF-2
Subtotal Liquid 2,075,135 215,175 46% 16,000

Jackson Prairie 1,092,099 30,337 7% 30,337 36 TF-2
Clay Basin 8,413,500 70,114 15% 70,114 120 TF-1
Subtotal Underground 9,505,599 100,451 22% 100,451

Grand Total 11,580,734 315,626 68% 116,451
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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.

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 9 below summarizes the Company’s year- round capacity
on NWP (TF-1) and its storage specific redelivery capacity (TF-2). Between the amount of capacity
Intermountain holds on the GTN, Foothills, and 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 9: Northwest Pipeline Transport Capacity

City Gate Delivery Quantity
(MMBtu per day) 2021 2022 2023 2024 2025 2026
Sumas Base Capacity 90,941 90,941 90,941 90,941 90,941 90,941
Sumas Segmentation and
Release (90,941) (90,941) (90,941) (90,941) (90,941) (90,941)
Segmentation 90,941 90,941 90,941 90,941 90,941 90,941
City Gate Supply
Total City Gate Delivery
Before TF-2 341,043 341,043 332,043 332,043 329,043 271,893

TF-2 Capacity -
Nampa LNG
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 27).

Because natural gas must flow along pipelines with finite flow capabilities, demand frequently
cannot be met from a market’s preferred basin. Competition among markets for these preferred
gas supplies can cause capacity bottlenecks and these bottlenecks often result in pricing
variations between basins supplying the same market area. In the short to medium term,
producers in constrained basins invariably must either discount or in some fashion differentiate
their product to compete with other also constrained supplies. In the longer run however,
disproportionate regional pricing encourages capacity enhancements on the interstate pipeline
grid, from producing areas with excess supply, to markets with constrained delivery capacity.
Such added capacity nearly always results in a more integrated, efficient delivery system that
tends to eliminate or at least minimize such price variances.

Figure 27: Pacific Northwest Pipelines Map
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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.”11

Supply Resources Summary
Because of the dynamic environment in which it operates, the Company will continue to evaluate
customer demand to provide an efficient mix of supply resources to meet its goal of providing
reliable, secure, and economic firm service to its customers. Intermountain actively manages its
supply and delivery portfolio and consistently seeks additional resources where needed. The
Company actively monitors natural gas pricing and production trends to maintain a secure,
reliable and price competitive portfolio and seeks innovative techniques to manage its
transportation and storage assets to provide both economic benefits to customers and
operational efficiencies to its interstate and distribution assets. The IRP process culminates with
the optimization model that helps to ensure that the Company’s strategies meet its traditional gas
supply goals and are based on sound, real-world, economic principles (see the Optimization
Model Section beginning on page 139).

11 https://www.eia.gov/outlooks/steo
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Capacity Release & Mitigation Process

Capacity Release & Mitigation Process
Overview
Capacity release was implemented by FERC to allow markets to more efficiently utilize pipeline
transportation and storage capacity. This mechanism allows a shipper with any such unused
capacity to auction the excess to another shipper that offers the highest bid. Thus, capacity that
would otherwise sit idle can be used by a replacement shipper. The result is a more efficient use
of capacity as replacement shippers maximize annualized use of existing capacity. One effect of
maximizing the utilization of existing capacity is that pipelines are less inclined to build new
capacity until the market recognizes that it is really needed and is willing to pay for new
infrastructure. However, a more fully utilized pipeline can also mean existing shippers have less
operational flexibility.
Intermountain has and continues to be active in the capacity release market. Intermountain
obtains significant amounts of unutilized capacity mitigation on NWP and GTN via capacity
releases. The Company frequently releases seasonal and/or daily capacity during periods of
reduced demand. Intermountain also utilizes a specific type of capacity release called
segmentation to convert capacity from Sumas to Idaho into two paths of Sumas to Stanfield and
Stanfield to Idaho. Intermountain uses the Stanfield to Idaho component to take delivery of the
lower cost AECO gas supplies that are delivered by GTN to the interconnect with NWP at
Stanfield. IGI Resources, Inc. (IGI) is then able to market the upper segment of Sumas to Stanfield
to other customers.
Capacity release has also resulted in a bundled service called citygate, in which gas marketers
bundle gas supplies with available capacity to be delivered directly to a market’s gate station.
This grants additional flexibility to customers attempting to procure gas supplies for a specified
period (i.e. during a peak or winter period) by allowing the customer to avoid contracting for
year-round capacity which would not be used during off-peak periods.
Pursuant to the requirements under the Services Agreement between Intermountain and IGI, IGI
is obligated to generate the maximum cost mitigation possible on any unutilized firm
transportation capacity Intermountain has throughout the year. In performing this obligation,
IGI must also ensure that: 1) in no way will there be any degradation of firm service to
Intermountain’s residential and commercial customers, and 2) that Intermountain always has
first call rights on any of its firm transportation capacity throughout the year and if necessary
Intermountain has the right to recall any previously released capacity if needed to meet core
market demands.
With the introduction of natural gas deregulation under FERC Order 436 in 1985 and the
subsequent FERC Orders 636, 712, 712A and 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
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Capacity Release & Mitigation Process

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.

Capacity Release Process
Because of its significant market presence in the Pacific Northwest, IGI has been able to generate
several millions of dollars per year in released capacity mitigation dollars on behalf of
Intermountain for pass-back to its core market customers and to reduce the cost of unutilized
firm transportation capacity rights. In this effort, IGI can determine what the appetite is in the
competitive marketplace for firm transportation releases on NWP and GTN. It does this via direct
communication with third parties or by market intelligence it receives from its marketing team
as it deals with its customers and other markets throughout the region. However, the most
effective way of determining interest in capacity releases is using the EBB. IGI performs its
obligation to Intermountain in one of two ways. First, if IGI itself is interested in utilizing any of
Intermountain’s unutilized firm transportation capacity, it determines what it believes is a market
competitive offer for such and that is then posted to the EBB as a pre-arranged deal. As a pre-
arranged deal, the transaction remains on the EBB for the requisite time and any third party has
the opportunity to offer a higher bid. If this is done, then IGI can chose to match the higher bid
and retain the use of the capacity, or not to match and the capacity will be awarded to the higher
third-party bidder.
Second, if IGI is not interested in securing any unutilized Intermountain capacity then it will post
such capacity to the EBB as available and subject to open bidding by any third party. As such, the
unutilized capacity will be awarded to the highest bidder. It should be noted that IGI posts to the
EBB, as available capacity, certain volumes of capacity for certain periods every month during bid
week. This affords the most exposure to parties that may be interested in securing certain
capacity rights. However, to date, third parties have chosen to bid on such available capacity only
a handful of times over all these years.
It should also be noted, that to protect the availability of firm transportation to Intermountain’s
residential and commercial customers during the year, all released capacity postings to the EBB,
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.
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Mitigation Process
IGI is also obligated to use its best efforts to mitigate the cost of transportation on the pipeline
facilities of Nova and Foothills when they are not being used by Intermountain for its own
needs. These pipelines are located in Canada and as such are not subject to the rules and
regulations of FERC Order 436, 636, 712(A) and 712(B). However, IGI uses much the same
evaluation methods for these Canadian pipelines as it does for NWP and GTN. IGI periodically
inquires with third parties as to any interest in potential unused capacity on Nova and Foothills
for certain periods of time known to be available. IGI also determines if it has any interest in
such available capacity for its use in serving other markets in the Pacific Northwest. There is no
EBB process on these Canadian pipelines. However, IGI employs much the same process as on
NWP and GTN to determine the best mitigation value for Intermountain. Also, similar to the
process on NWP and GTN, any of the unused NOVA and Foothills capacity used by IGI or other
third parties is always subject to recall should Intermountain have any need for that capacity to
serve its customers.

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Non-Traditional Supply Resources

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
Non-Traditional Resources
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.
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
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Non-Traditional Supply Resources

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.
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.
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.
Wood Chips
Historically Intermountain has had one large volume industrial customer on the IFL that had the
ability to utilize wood chips as an alternative fuel. However, after a recent expansion it is unclear
how much or often this customer utilizes this alternative fuel. In order to accommodate wood
burning there must be additional equipment installed, such as wood fired boilers, wood chip
transport and dry storage facilities. The wood is supplied from various tree clearing and wood
mill operations that produce chips within regulatory specifications to be used as fuel. The chips
are then transported by truck to the location where the customer could utilize them as a fuel
source for a few months each year.
The cost of wood is continually changing based on transportation, availability, location and the
type of wood processing plant that is providing the chips. Wood has a typical value of 5,000-6,000
BTU’s per pound, which converts into 16-20 pounds of wood being burned to produce one therm
of natural gas.
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Non-Traditional Supply Resources

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

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Non-Traditional Supply Resources

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.
Intermountain has included RNG as a potential resource to solve any supply shortfalls the
Company may have. RNG that has been cleaned to the Company’s specifications can be used
interchangeably with traditional natural gas in Intermountain’s pipelines and in the customers’
end use equipment. The Company estimated the price of RNG at $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.”12 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 on in the Planning Results section.
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.”13 Hydrogen can be produced by a variety of sources that are delineated by
colors:

12 https://gasfoundation.org/wp-content/uploads/2019/12/AGF-2019-RNG-Study-Full-Report-FINAL-12-18-19.pdf
13 https://www.nrel.gov/docs/fy21osti/77610.pdf
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Non-Traditional Supply Resources

• 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.”14 With a conversion rate for kg per 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”).15 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.

14 https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/experts-explain-why-green-hydrogen-costs-have-fallen-and-will-keep-falling-63037203
15 https://www.energy.gov/eere/fuelcells/hydrogen-shot
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Lost and Unaccounted For Natural Gas Monitoring

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 three-year average LAUF percentage of -0.1193% (see Figure 28 below).

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
Figure 28: Intermountain LAUF Statistics
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Lost and Unaccounted For Natural Gas Monitoring

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.
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 10: 2018 - 2020 Billing and Meter Audit Results
Billing and Meter Audit Results
2018 2019 2020
Dead Meters 310 211 184
Drive Rate Errors 4 1 2
Pressure Errors 24 21 14
Totals 338 233 200

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.

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
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Lost and Unaccounted For Natural Gas Monitoring

are graded and addressed according to grade. Grade 1 leaks are repaired immediately, Grade 2
leaks are addressed within six months, and Grade 3 leaks are addressed within 15 months. This
approach is more aggressive than the industry standard, where lower grade leaks are often
monitored for safety and not repaired immediately.

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”.
A damage prevention department has been created for the utility group. The department focuses
on education to both business and agencies that interact with Intermountain and the public.
Industry education and awareness has centered around trainings with contractors, excavators
and first responders.
To educate the general public on the importance of calling 811 prior to any type of digging,
Intermountain has participated in a variety of informational activities. The Company sponsors
many events and activities across the state of Idaho each year.
The additional focus on education and awareness is having an impact. Intermountain has seen a
decrease in incidents that damage facilities, and especially a decrease in incidents that cause gas
loss. There is still work to do, however. There continue to be instances where the contractor or
individual either does not call 811 before digging or calls but does not pay attention to the
marking of the utility facilities. Continued focus on damage prevention by Intermountain as well
as the support of the Idaho Damage Prevention Board should help to further reduce the
incidences of excavation damage and related gas loss in the future. Figure 29 shows the damage
rate per 1,000 locates, and Figure 30 shows the total locates for 2018 through 2020.

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

Figure 30: Intermountain Locate Requests by Region
Figure 31 below shows total damages by region and year for 2018 through 2020.
8.12 7.29 6.737.37
5.62 5.54
7.64
6.17 5.92
2018 2019 2020
DAMAGES RATE PER 1,000 -BY REGION
East Region West Region Company Totals
35,571 35,780 40,146
64,593 73,267
84,162
100,164 109,047
124,308
-
20,000
40,000
60,000
80,000
100,000
120,000
140,000
2018 2019 2020
LOCATE REQUESTS -BY REGION
East Region West Region Company Totals
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Figure 31: Intermountain Total Damages by Region

Advanced Metering Infrastructure
Intermountain is in the process of implementing Itron’s fixed-network metering infrastructure. In
the Company’s previous IRP, it was anticipated that the system would be complete by the end of
2020. However, COVID-19 and the related labor and supply chain issues have hampered
installation efforts. The system is currently 60% complete and is planned to reach 90% coverage
by the end of 2022. This system utilizes a fixed mounted data collector using two-way
communication to endpoints and to the repeater to collect on-demand reads and issue network
commands. This system provides a robust collection of time-synchronized interval data, and
when coupled with a meter data management system, it helps Intermountain:
• Improve customer service
• Refine forecasted consumption
• Manage and control tampering and theft
• Synchronize endpoint clocks to ensure data collected territory-wide is accurately time-
stamped
• Retrieve missing interval data in the event of an outage
• Streamline the process of identifying billing errors

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
289 261 270
476 412 466
765
673 736
2018 2019 2020
TOTAL DAMAGES -BY REGION
East Region West Region Company Totals
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Lost and Unaccounted For Natural Gas Monitoring

weather and temperature monitoring provide for a better temperature component of the billing
factor used to calculate customer energy consumption.
Summary
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.

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Core Market Energy Efficiency

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.

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.
Collections 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 and energy savings. Intermountain launched its Commercial EE Program on April 1,
2021 and began collecting funds through an Energy Efficiency Charge.

Conservation Potential Assessment
In its 2019 IRP, the Company estimated DSM therm savings for the 2019-2023 planning period
based on the Conservation Potential Assessment (CPA) commissioned by Intermountain. The CPA
provides 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 CPA is intended to be used for the following:
• Resource planning: evaluate the impact of energy efficiency, fuel switching and codes
and standards on long-term energy consumption and demand needs
• Identify opportunities: assess achievable DSM opportunities to improve DSM program
planning and help meet long-term savings objectives, and determine which sectors, end-
uses and measures hold the most potential
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Core Market Energy Efficiency

• Efficiency program planning: inform portfolio and program design considering funding
level, market readiness and other constraints.
Dunsky Energy Consulting (Dunsky) was retained to perform the assessment. Dunsky utilized the
expertise of GTI, the leading natural gas energy and environmental research organization, as the
primary research lead for the study. The scope of the study included conservation potential for
both the residential and commercial sectors, over the 2020-2039 time period.
The purpose of the potential assessment was “to provide a realistic, high-level assessment of the
long-term energy efficiency potential that is technically feasible, cost-effective, and achievable
through efficiency programs.” Three categories of potential savings, depicted in Figure 32, were
examined by applying economic considerations such as market barriers and cost tests. The Utility
Cost Test (UCT) was applied to the theoretical maximum savings opportunity, or the technical
savings category, to screen for only the cost-effective measures, resulting in the economic
savings potential. The economic savings potential of cost-effective measures was further
screened by applying market barriers to establish the achievable energy efficiency potential. To
study the impacts on achievable potential savings, three different scenarios were tested: the low
case, the base case and the max case. A more detailed description of the methodology can be
found in the final CPA report completed in 2019, and attached as Exhibit 4.

Figure 32: Categories of Potential Savings
Details of the three scenarios and the key insights to be examined with each scenario were as
follows:
• Low Case - low incentive levels, (35% of incremental measure costs), but with no budget
constraints and over a broad set of cost-effective measures
Key insight: What level of saving can be achieved with a comprehensive offer, with
incentives that are in the lower range?

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Core Market Energy Efficiency

• Base Case – incentives increased to 50%, barrier reduction in Program Year 6,
unconstrained budget – standard program approach
Key insight: How much more savings can be expected with increased incentive
levels?

• Maximum Case – incentive levels at 65%, barrier-reducing program delivery,
unconstrained budget and measures
Key Insight: How would improved program delivery increase savings (e.g.
consumer education, contractor training and support, etc.)
In addition to the CPA report, Dunsky provided a savings modeling tool called the Dunsky Energy
Efficiency Potential Model (DEEP Model), which employs a multi-step process to develop the
Technical, Economic and Achievable potentials as shown in Figure 33. Since the 2019 IRP,
Intermountain updated the DEEP model to align with the 2021-2026 planning window, utilize the
latest avoided cost calculations and to reflect the introduction of the Commercial EE Program.

Figure 33: Key Steps and Inputs in Study Methodology

Therm Savings
As seen in Figure 34 below, cumulative therm savings for 2021-2026 from the DEEP Model are
shown by category of potential savings and by the three scenarios of achievable potential (low,
base and max).
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Core Market Energy Efficiency

Figure 34: Cumulative Therm Savings
Focusing strictly on the Achievable Base scenario, Figure 35, shows the cumulative potential
therm savings, by program, for the 2021-2026 time period.

Figure 35: Cumulative Therm Savings, Base Achievable Scenario
As shown in Figure 36, 69% of achievable savings will come from the residential sector. The three
next highest achievable savings all come from the commercial sector: education (12%), retail and
food sales (5%), and office (5%).
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Core Market Energy Efficiency

Figure 36: Achievable Savings by Segment 2021 - 2026
The achievable savings by application for the combined sectors, commercial and residential, is
shown in Figure 37.

Figure 37: Achievable Savings by Application 2021 - 2026
In the residential sector, the CPA identified envelope and HVAC applications as the two largest
categories of potential savings. The top HVAC measures identified included connected
thermostats, duct insulation and efficient boilers. To capture these savings potentials,
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Core Market Energy Efficiency

Intermountain revised its Residential EE Program to add smart thermostats and high-efficiency
boilers. Furthermore, the Whole Home rebate for new construction was updated to include
specific energy performance targets for maximum air change per hour limits achieved by
improved air sealing and reducing duct leakage allowances through better duct insulation and
above-code ceiling insulation requirements. These changes that are targeted to improve therm
savings became effective April 1, 2021.
In the commercial sector, HVAC applications also provided the greatest savings potential.
Equipment-based measures like condensing boilers and energy recovery ventilators represented
a significant share of potential in the first five years of the program. Commercial kitchen
appliances were also identified as an untapped savings opportunity. As mentioned above,
Intermountain launched its Commercial EE Program on April 1, 2021 with a modest initial offering
of rebates for condensing boilers, boiler reset controls, condensing unit heaters, and commercial
kitchen equipment. A complete listing of Commercial Energy Efficiency Rebates is shown in Figure
38.

Figure 38: Commercial Energy Efficiency Rebates
Savings potential from the base scenario were incorporated as a DSM resource in the
Optimization Model.
Ensuring an Energy Efficient Future
Intermountain Gas is committed to the efficient use of natural gas today, and also works to secure
an energy efficient future. Intermountain has been a long-time member of the Gas Technology
Institute (GTI). GTI is the leading research, development and training organization addressing
energy and environmental challenges to enable a secure, abundant, and affordable energy
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Core Market Energy Efficiency

future. As a GTI member, Intermountain is able to leverage research and development
investments by collaborating with other interested members in funding and steering the
direction of a project, while allowing GTI to manage the program and perform the research.
Intermountain participates on the Operations Technology Development (OTD) and Utilization
Technology Development (UTD) collaborative member groups which are focused on different
aspects of the value chain. OTD is a member-controlled partnership to develop, test, and
implement new technologies related to the safe and reliable operation of the natural gas
infrastructure. UTD, also a member-controlled partnership, conducts near-term applied research
to develop, test and deploy energy-efficient end-use technologies.
Intermountain’s Energy Efficiency Program participates specifically in UTD’s Emerging
Technology Program (ETP), which is a member-driven collaborative to accelerate the
introduction and acceptance of new emerging technologies for energy efficiency programs. ETP
picks up at the final stages of UTD’s research process and focuses on “identifying and addressing
data or market barriers, including the development of new measures, impacts of disruptive
technologies, awareness and education.” Gas heat pumps are an emerging technology that has
been a part of the ETP program and is well positioned to take the next step in becoming a
commercially available product.
To build on GTI’s work in gas heat pump technology, Intermountain joined the North American
Gas Heat Pump Collaborative (Collaborative) as a charter member. The Collaborative is a coalition
of 14 gas utilities and energy efficiency administrators representing 31% of gas-served
households in North America. Its mission is to advance the successful commercialization of gas
heat pump technology from pre-commercialization, to product rollouts, to realization of a
mature commercial marketplace. This effort is part of a larger strategy to enable the gas industry
to play a significant role in the decarbonization of energy and the development of a cleaner
economy. Intermountain participates on the operations committee, the gas heat pump water
heater working group and the residential combination working group. The Collaborative
continues to make excellent progress as a newly formed North American effort advancing the
adoption of gas heat pump technology.
To further the effort of securing a clean energy future, Intermountain also joined the newly
formed Low-Carbon Resources Initiative (LCRI) which is a joint venture of GTI and the Electric
Power Research Institute (EPRI). This is a unique, international collaboration spanning the natural
gas and electric sectors that will help advance global, deep decarbonization of all segments of
the economy. The goal of the five-year initiative is to accelerate the development and
demonstration of low-carbon energy technologies, leading to affordable options to accelerate an
intelligent transformation toward a cleaner, reliable, and affordable energy future by mid-
century.

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Large Volume Energy Efficiency

Large Volume Energy Efficiency

Through discussions with the customers and the information provided via the IRP surveys, it is
apparent that 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 20 years ago Intermountain developed an
informational tool using 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.

In order to provide customers access to this data, Intermountain has designed and hosts a Large
Volume website, which is pictured in Figure 39. The website is available on a 24/7 basis for Large
Volume customers to log-in via the internet using a 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 40. The user can also download the data in CSV
format to review, evaluate, save and analyze natural gas consumption at their specific facility on
an hourly, weekly, monthly, and annual basis as far back as 2017. Each customer may elect to
Figure 39: Large Volume Website Login
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Large Volume Energy Efficiency

have one or multiple employees access the site. Logins can also be created to make this same
data available to a transport customer’s natural gas marketer.

Figure 40: Natural Gas Usage History

The website also contains a great deal of additional information useful to the Large Volume customer. Customers
can access information such as the different tariff services offered, answers to frequently asked questions
and a potential marketer list for those interested in exploring transport service. The customer is also
provided a “Contact Us” link and, in order to keep this site in the most usable format for the
customer, a website feedback link is provided. The site allows the Company to post information
regarding things such as system maintenance, price changes, rate case information and any other
communication that might assist the customer or its marketer.

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Avoided Costs

Avoided Costs

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.

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%.
• The discount rate is derived using Intermountain’s tax-effected cost of capital.
• Standard present value and levelized cost methodologies are utilized to develop a
real and nominal levelized avoided cost by year.

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Avoided Costs

Understanding Each Component
Commodity Costs
Commodity costs represent the purchase price of the natural gas molecules that the Company
does not need to buy due to therm savings generated by its Energy Efficiency Program. To
calculate the commodity costs, the Company first utilizes price forecasts included in its IRP for
three primary basins (AECO, Sumas, and Rockies) then weights these forecasts based on
Intermountain’s historical day-gas purchase data. Day-gas purchases 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.

Transportation Costs
Transportation costs are the costs the Company incurs to deliver gas to its distribution system.
As the Company’s Energy Efficiency Program generates therm savings, the Company can reduce
pipeline capacity needs and monetize any excess capacity to reduce costs for all customers
through credits in the Company’s annual Purchased Gas Cost Adjustment (PGA) filing. The
Company calculates the per therm transportation cost as the weighted average of the gas
transportation costs listed on the Company’s residential and commercial tariffs. The nominal
value of the transportation cost is increased each year by the model inflation rate of 2.0%. The
inflated nominal value is then discounted back to today's dollars as part of the final step in the
avoided cost calculation. The Company will update the transportation cost each year to reflect
the most current gas transportation cost as filed in its PGA.

Variable Distribution Costs
Variable distribution costs are the avoidable portion of costs incurred by Intermountain to
deliver gas to customers via its distribution system. Lowering gas consumption through the
Company’s Energy Efficiency Program allows Intermountain to delay costly capacity
expansion projects and utilize existing pipeline infrastructure more efficiently. While these
cost benefits are intuitively apparent, the Company and its Stakeholder group are
investigating methods to quantify these savings. The Company is currently using a
placeholder value of zero for this component.

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Distribution System Modeling

Optimization

Distribution System Modeling
Overview
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 volume 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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I n t e g r a t e d R e s o u r c e P l a n 2 0 2 1 -2 0 2 6 93
Distribution System Modeling

Modeling Methodology
Intermountain utilizes a hydraulic gas network modeling and analysis software program called
Synergi Gas, distributed and supported by DNV, 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 high pressure laterals, intermediate pressure systems, 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. The entire pipeline system is broken into
three individual models for ease of use and to reduce the time requirements during a model run
analysis. The largest model in use consists of approximately 71,500 active nodes, 580,000 graphic
nodes and 76,400 facilities which are used along with additional model inputs to solve
simultaneous equations through an iterative process, calculating pressures for over 70,500
unknown locations prior to analysis.
Synergi can analyze a pipeline system at a single point in time or the model can be specifically
designed to simulate the flow of gas over a specified period of time; which more closely simulates
real life operation utilizing gas stored in pipelines as line pack. While modeling over time an
engineer can write operations that will input and/or manipulate the gas loads, time of gas usage,
valve operation and compressor simulations within a model, and by incorporating the forecasted
customer growth and usage provided within this integrated resource plan Intermountain can
determine the most likely points where future constraints may occur. Once these high priority
areas are identified, research and model testing are conducted to determine the most practical
and cost-effective methods of enhancing the constrained location. The feasibility, timeline, cost
and increased capacity for each theoretical system enhancement is determined and then placed
into a comparison analysis and used within the IRP model.

Intermountain Gas Company
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Capacity Enhancements

Capacity Enhancements

Overview
Throughout previous sections of the IRP, it has been shown that projected growth throughout
Intermountain’ 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. For each capacity deficit identified, the Company
evaluates and compares potential system capacity enhancements in its optimization model and
selects a final capacity enhancement based on cost, capacity increase and long-term planning.
After the capacity enhancement has been selected it is included in Intermountain’s 5-year budget
based on when the capacity enhancement needs to occur to avoid capacity deficiencies.
The net present value (NPV) costs for each potential capacity enhancement are presented in the
discussion below. To determine the NPV costs, the Company compared the initial project cost to
the estimated annual costs of the project, inflated by 2% each year and discounted to current
dollars using the nominal discount rate of 6.68% from the Company’s avoided cost model
presented in Exhibit 5. The final NPV calculations can be found attached in Exhibit 6.
The summary presented at the end of this section shows the timing for all capacity enhancements
selected and the corresponding capacity increases for each AOI.

Capacity Enhancement Options
The capacity enhancements discussed in this section are as follows:
1. Pipeline Loop
2. Pipeline Uprate
3. Compressor Station
4. Pipeline Replacement
These capacity enhancements do not reduce demand nor do they create additional supply points,
rather they increase the overall capacity of a pipeline system while utilizing the existing gate
station supply points.
Pipeline Loop
Pipeline looping is a traditional method of increasing capacity within an existing distribution
system. The loop refers to the construction of new pipe installed parallel to an existing pipeline
that has, or may become, a constraint point. The feasibility of looping a pipeline is primarily
dependent upon the location where the pipeline will be constructed. Installing gas pipelines
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Capacity Enhancements

through private easements, residential areas, existing asphalt, or steep and rocky terrain can
greatly increase the cost to unjustifiable amounts when compared with alternative enhancement
solutions.

Pipeline Uprate
A pipeline uprate is a method of increasing the capacity of an existing pipeline by increasing the
maximum allowable operating pressure of the pipeline. Operating a pipeline at a higher pressure
allows for greater throughput down the pipeline. Uprates allow a company to maximize the
potential of their existing systems before constructing additional facilities and they are normally
a lower-cost option compared to pipeline looping to increase capacity; however, leaks and
damages are sometimes found or incurred during the uprate process creating costly repairs.
There are also safety considerations and pipe regulations that restrict the feasibility of increasing
the pressure in any pipeline, such as the material composition, pressure test, operations and
maintenance history of the pipeline and location of the existing pipeline. Another consideration
to an uprate is if the uprate could take the specific maximum yield stress (SMYS) of the pipeline
into Transmission Classification. Increased regulatory requirements would incur increased
operations and maintenance costs for Transmission class lines.

Compressor Station
Compressor stations are typically installed on large diameter pipelines or laterals that run several
miles and have significant gas flow demands. Compressor stations boost pressures and flows
down the lateral to meet delivery pressure needs on the system and can be a feasible solution to
lateral point constraints. Regulatory and environmental approvals to install a compressor station
can be a significant deterrent and not all site locations may be favorable. Operation and
maintenance of the compressor should also be considered in the analysis since compressors
require additional cost to run and maintain the compressor and without redundancy could
require outage coordination if the compressor needs to be taken offline to make repairs.

Pipeline Replacement
A fourth option to gain capacity on a pipeline that cannot be uprated or does not have a feasible
route to loop the line is to replace the pipeline with a new pipeline that meets design
specifications for the demand. Pipeline replacements should be considered on older vintage pipe
that does not have all of the pipeline records required to uprate the line. Pipeline replacement
would also be considered if the line has an integrity concern or potential issue that would not be
favorable to uprate the line.

Intermountain Gas Company
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Capacity Enhancements

Canyon County

AOI Summary/System Dynamics
The Canyon County AOI 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 provided a secondary feed to the
Canyon County area. The next large system enhancement occurred in 2018 with the 12-inch
Ustick Phase I HP pipeline project installed on the east side of Caldwell.

Capacity Limiter
Due to significant growth in Nampa and surrounding communities this AOI requires a capacity
enhancement by both 2021 and 2023 to meet IRP growth predictions. The Canyon County AOI’s
capacity is currently limited by high flow rates on the 6-inch, 8-inch and 10-inch HP pipeline on
Ustick Rd which is causing high pressure to drop in this section, compromising pressures
downstream, and impacting the line’s capacity. This bottleneck is highlighted in yellow in Figure
41.

Figure 41: Canyon County Capacity Limiter

Capacity Enhancement Alternatives Considered
Alternative One: Ustick Phase II
The first capacity enhancement alternative is to install 2 miles of 12-inch steel HP pipe along
Ustick Rd as shown in Figure 42.
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Capacity Enhancements

Figure 42: Canyon County Alternative One
This option will bring the capacity up to 1,032,000 therms per day which will meet predicted
growth through 2022 and will allow IGC to downrate the existing 6-inch HP pipe to distribution
pressure (DP), boost the distribution system capacity, and allow for the retirement of a DP
regulator station and several high-pressure service sets (HPSS). This option was selected in the
2019 IRP. NPV cost for this option is estimated at $3,255,075
Alternative Two: Ustick Phase III
The second capacity enhancement alternative is to install 4.1 miles of 12-inch steel HP pipe along
Ustick Rd and install 4 HP regulator stations as shown in Figure 43.

Figure 43: Canyon County Alternative Two

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Capacity Enhancements

This project builds off the Phase I and Phase II enhancements and would increase capacity to
1,390,000 therms per day which would meet growth through 2026. Completing this project
would allow IGC to downrate the existing 10-inch and 8-inch HP pipelines on Ustick Rd to DP and
eliminate several regulator stations and HPSS’s. Eliminating these stations would reduce
operations and maintenance costs. NPV cost for this option is estimated at $8,613,403.

Alternative Three: Ustick Uprate
The third capacity enhancement alternative is to retest and then uprate the 4.1 miles of 10-inch
HP steel pipe and 3.1 miles of 8-inch HP steel pipe on Ustick Rd and install 4 HP regulator stations
as shown in Figure 44.

Figure 44: Canyon County Alternative Three

This option would bring the capacity up to 1,178,000 therms per day which would meet predicted
growth through 2026 assuming Ustick Phase II has been completed. Other considerations
associated with this uprate include unknowns with pressure testing 1956 vintage pipe and the
potential that this pipe could not pass uprate requirements to operate at a higher pressure. NPV
cost for this option is estimated at $1,300,000.

Alternative Four: 8-inch HP extension north of Ustick at 500 psig MAOP
The fourth capacity enhancement alternative is to install 6.5 miles of 8-inch HP steel pipe north
of Ustick Rd on Linden Rd and a HP regulator station as shown in Figure 45.

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Capacity Enhancements

Figure 45: Canyon County Alternative Four
This option would bring the capacity up to 1,232,000 therms per day which would meet predicted
growth through 2026 assuming Ustick Phase II has been completed. NPV cost for this option is
estimated at $6,551,492.

Table 11: Canyon County Alternative Summary
Alternative
#
Alternative
Description NPV Cost ($)
Capacity
(th/day)
Alternative Capacity
Gain (%)
1 Ustick Phase II $3,255,074.59 1,032,000 0%
2 Ustick Phase III $8,613,402.92 1,390,000 35%
3 Ustick Uprate $1,300,000.00 1,178,000 14%
4 north of Ustick $6,551,492.43 1,232,000 19%

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Capacity Enhancements

Capacity Enhancement Selected
Intermountain selected alternative one (Ustick Phase II) in the 2019 IRP. Alternative two (Ustick
Phase III) has been selected to meet 2026 growth predictions. Alternatives one and two provide
the highest capacity to the AOI and continues upon Intermountain’s long term planning for the
Ustick HP system to operate at 500 psig. Additionally, the Company determined that constructing
a new line with defined costs is preferable to the uprate option which has unknown costs and
could have significant cost creep due to the uncertainty of pressure testing the vintage pipe.
Ustick Phase II is currently in construction and will be completed by the end of 2021 and Ustick
Phase III will begin design in 2022 with construction planned to be completed in 2023.

State Street Lateral

AOI Summary/System Dynamics
The State Street Lateral is a 16-mile stretch of high pressure, large diameter main that begins in
Middleton and runs east along State Street serving the towns of Star, north Meridian, Eagle and
into northern Boise. The lateral is fed directly from a gate station along with a back feed from
another high-pressure pipeline from the south. Much of the pipeline is closely surrounded by
residential and commercial structures that create a difficult situation for construction and/or
large land acquisition, thus making a compressor station or Liquified Natural Gas (LNG)
equipment less favorable.

Capacity Limiter
Due to significant growth in Boise and north of Boise this AOI requires a capacity enhancement
by 2023 to meet IRP growth predictions. 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
46 below.
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Capacity Enhancements

Figure 46: State Street Capacity Limiter

Capacity Enhancement Alternatives Considered
Alternative One: State Street Phase II Uprate
The first capacity enhancement alternative is to retest and then uprate the 2.3 miles of 12-inch
HP steel pipe on State Street and 2 miles of 4-inch HP steel pipe on Linder Road and install a HP
regulator station as shown in Figure 47. In addition, this project will require 2.3 miles of 6-inch
plastic trunk line on State Street and a 2-mile 4-inch plastic trunk line on Linder Road paralleling
the uprate to allow Intermountain to maintain service while the HP pipes are taken out of service
for the retest and uprate.
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Capacity Enhancements

Figure 47: State Street Alternative One

This option would bring the capacity up to 950,000 therms per day which would meet predicted
growth through 2026. Other considerations associated with this uprate include unknowns with
pressure testing 1964 vintage pipe and the potential that this pipe could not pass uprate
requirements to operate at a higher pressure. However, in 2019 the State Street Phase 1 uprate
was successful without any major issues. Uprating this line would also bring the 12-inch HP on
State Street to transmission classification which would increase future operations and
maintenance costs. This project would allow Intermountain to retire several HP and DP regulator
stations. NPV cost for this option is estimated at $2,030,592.

Alternative Two: Replace 12-inch HP pipe on State Street and Replace 4-inch HP pipe on
Linder to operate at 500 psig MAOP
The second capacity enhancement alternative is to replace the 2.3 miles of 12-inch HP steel pipe
on State Street and 2 miles of 4-inch HP steel pipe on Linder Road and install an HP regulator
station as shown in Figure 48.
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Capacity Enhancements

Figure 48: State Street Alternative Two
This option would bring the capacity up to 950,000 therms per day which would meet predicted
growth through 2026. This project would allow IGC to retire a couple HP regulator stations and
the new line would be designed to be an HP line. NPV cost for this option is estimated at
$5,536,657.
Table 12: State Street Alternative Summary
Alternative
#
Alternative
Description NPV Cost ($)
Capacity
(th/day)
Alternative Capacity
Gain (%)
1 Uprate $ 2,030,591.75 950,000 16%
2
State St and Linder to
operate at 500# $ 5,536,656.65 950,000 16%

Capacity Enhancement Selected
Intermountain selected alternative one (State Street Phase II Uprate) to meet 2026 growth
predictions. Alternative one is the lowest cost option, and because Intermountain recently
pressure tested and uprated State Street Phase I (completed in 2019), the Company does not
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Capacity Enhancements

expect any issues associated with the pressure test or uprate. State Street Phase II Uprate is
currently in design with construction planned to be completed in 2023.

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 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 and Meridian the Central Ada County AOI requires a capacity
enhancement by 2022 to meet IRP growth predictions. The current capacity limiter for this AOI
is a 10-inch and 8-inch HP bottleneck on Meridian Rd and Victory Rd directly downstream of the
Meridian Gate as shown in yellow in Figure 49 below.
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Capacity Enhancements

Figure 49: Central Ada County Capacity Limiter
Capacity Enhancement Alternatives Considered
Alternative One: 12-inch South Boise Loop
The first capacity enhancement alternative is to install 3.7 miles of 12-inch HP steel pipe on
Cloverdale Road from the Kuna Gate north to Victory Road as shown in Figure 50. In addition,
this project would require the Kuna gate station be upgraded and installation of a HP regulator
station located at Victory Road and Cloverdale Road.

Figure 50: Central Ada County Alternative One

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Capacity Enhancements

This option would bring the capacity up to 870,000 therms per day which would meet predicted
growth through 2026. This project would provide a third feed into the Boise HP system and would
loop the Nampa, Meridian and Kuna gates. NPV cost for this option is estimated at $10,321,364.

Alternative Two: Uprate 10-inch HP on Meridian and Victory Rd to operate at 500 psig
The second capacity enhancement alternative is to retest and then uprate 2.5 miles of 10-inch
HP steel pipe on Meridian Road and Victory Road and install two new HP regulator stations as
shown in Figure 51.

Figure 51: Central Ada County Alternative Two
This option would bring the capacity up to 817,000 therms per day which would meet predicted
growth through 2026. Other considerations associated with this uprate include unknowns with
pressure testing 1956 vintage pipe and the potential that this pipe could not pass uprate
requirements to operate at a higher pressure. Uprating this line would also bring the 10-inch HP
on Meridian Road and Victory Road to transmission classification which would increase future
operations and maintenance costs. Another consideration to this uprate is both Meridian Road
and Victory Road are high traffic areas and any work on this road would require extensive traffic
control and detours which could impact city projects and would make this project very
challenging to schedule and it would be expensive to restore excavations associated with the
pressure test. NPV cost for this option is estimated at $2,034,763.
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Capacity Enhancements

Alternative 3: Install compressor station on Victory Rd to boost pressure to 380 psig at
Cloverdale
The third capacity enhancement alternative is to install a Compressor Station near Victory Road
and Cloverdale Road as shown in Figure 52.

Figure 52: Central Ada County Alternative Three

This option would bring the capacity up to 817,000 therms per day which would meet predicted
growth through 2026. Other considerations associated with installing a compressor station
within city limits is it would be unlikely to find a two-acre site near the Company’s existing 10-
inch pipeline. To install a compressor, the Company would also need to obtain a compressor
permit and it is uncertain if Intermountain could obtain a permit in this area. Intermountain
would also have additional cost to run and maintain the compressor and a compressor provides
no redundancy or system looping to Intermountain’s system. NPV cost for this option is
estimated at $12,807,602.

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Capacity Enhancements

Table 13: Central Ada County Alternative Summary
Alternative
#
Alternative
Description NPV Cost ($)
Capacity
(th/day)
Alternative Capacity
Gain (%)
1
12-
Loop $ 10,321,364.12 870,000 17%
2 Rd $ 2,034,763.35 817,000 10%
3 Cloverdale $ 12,807,602.46 817,000 10%

Capacity Enhancement Selected
Intermountain selected alternative one (12-inch South Boise Loop) to meet 2026 growth
predictions. When compared to alternative three, alternative one provides the highest capacity
increase to the AOI, the lowest cost, and is the more feasible option. Additionally, the Company
determined that constructing a new line with defined costs is preferable to the uprate option
which has unknown costs and could have significant cost creep due to the uncertainty of pressure
testing the vintage pipe. Furthermore, alternative one provides a significant benefit because
upgrading the Kuna gate station will add a second feed to the Boise HP systems and provide
looping to the HP system fed from the Nampa gate station. The 12-inch South Boise Loop is
currently in design with construction planned to be completed in 2022.

Sun Valley Lateral

AOI Summary/System Dynamics
The Sun Valley Lateral is a 68-mile-long, 8-inch high pressure pipeline that has almost its entire
demand at the far end of the lateral away from the source of gas. Obtaining land near this
customer load center is either expensive or simply unobtainable. 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 Enhancements

Capacity Limiter
Due to growth in Sun Valley this AOI requires a capacity enhancement to meet IRP growth
predictions. 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 53.

Figure 53: Sun Valley Capacity Limiter

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Capacity Enhancements

Capacity Enhancement Alternatives Considered

Alternative One: Shoshone Compressor Station
The first and only capacity enhancement alternative considered is to install a second compressor
station near Mile Post (MP) 32 near Shoshone on the Sun Valley Lateral as shown in Figure 54.
This project was previously evaluated and selected in the Company’s 2019 IRP filing.

Figure 54: Sun Valley Lateral Alternative One

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Capacity Enhancements

This option will bring the capacity up to 247,500 therms per day which will meet predicted growth
through 2026. A compressor permit will be required for this project. IGC will have additional cost
to run and maintain the compressor and a compressor provides no redundancy or system looping
to Intermountain’s system. NPV cost for this option is estimated at $5,807,602.

Table 14: Sun Valley Lateral Alternative Summary
Alternative #
Alternative
Description NPV Cost ($)
Capacity
(th/day)
Alternative Capacity
Gain (%)
1
Compressor
Station $ 5,807,602.46 247,500 0%

Capacity Enhancement Selected
Intermountain selected alternative one (Shoshone Compressor Station) to meet 2026 growth
predictions in the 2019 IRP. The Shoshone Compressor Station has been ordered and
construction will be completed in the summer of 2022.

Idaho Falls Lateral

AOI Summary/System Dynamics
The Idaho Falls Lateral began as a 52-mile, 10-inch pipeline that originated just south of Pocatello
and ended at the city of Idaho Falls. The IFL was later expanded farther to the north extending
an additional 52 miles with 8-inch pipe to serve the growing towns of Rigby, Lewisville, Rexburg,
Sugar City and Saint Anthony. As demand has continually increased along the IFL, Intermountain
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 loop.

Capacity Limiter
Due to growth in Idaho Falls this AOI requires a capacity enhancement by 2023 to meet IRP
growth predictions. The current capacity limiter for this AOI is the end of line pressure on the
lateral to St. Anthony as shown in yellow in Figure 55.
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Capacity Enhancements

Figure 55: Idaho Falls Lateral Capacity Limiter

Capacity Enhancement Alternatives Considered
Alternative One: Blackfoot Compressor Station
The first enhancement alternative considered is to install a compressor station near Blackfoot, ID
on the Idaho Falls lateral as shown in Figure 56.
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Capacity Enhancements

Figure 56: Idaho Falls Lateral Alternative One
This option would bring the capacity up to 1,093,000 therms per day (assumes Rexburg LNG is
offline) which would meet predicted growth through 2026. A compressor permit would be
required for this project. Intermountain will have additional cost to run and maintain the
compressor and a compressor provides no redundancy or system looping to the Company’s
system. NPV cost for this option is estimated at $15,807,602.

Alternative Two: Phase VI with a second Satellite LNG tank at Rexburg
The second enhancement alternative considered is to install a second satellite LNG tank at
Rexburg and install 10.5 miles of 16-inch pipe from Iona to Rigby as shown in Figure 57.

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Capacity Enhancements

Figure 57: Idaho Falls Lateral Alternative Two
This option would bring the capacity up to 963,000 therms per day which would meet predicted
growth through 2026. This option would provide looping and redundancy to the Company’s
system, but the Rexburg LNG site would still be required. NPV cost for this option is estimated at
$23,246,006.
Table 15: Idaho Falls Lateral Alternative Summary
Alternative
#
Alternative
Description NPV Cost ($)
Capacity
(th/day)
Alternative Capacity
Gain (%)
1 Station 15,807,602.46 1,093,000 21%
2 Rexburg
$
23,246,006.08 963,000 7%

Intermountain Gas Company
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Capacity Enhancements

Capacity Enhancement Selected
Intermountain selected alternative one (Idaho Falls Lateral Compressor Station) to meet 2026
growth predictions. This is the lowest cost alternative and provides the largest capacity increase
to the AOI. The Idaho Falls Compressor Station will be designed in 2022 and construction is
planned for 2023.
With the decision to add the Blackfoot compressor station, Intermountain will need to keep the
Rexburg satellite LNG facility as a peak shaving facility until 2023 when the Blackfoot compressor
station comes online. After 2023, Intermountain plans to keep the Rexburg satellite LNG facility
as an emergency backup to provide additional system reliability to the Idaho Falls lateral.

Summary
Table 16 provides a summary of the capacity enhancements selected by AOI based on the analysis
above.

Intermountain Gas Company Capacity Enhancements

Table 16: AOI Capacity Summary and Timings
AOI
→ Central Ada County State Street Lateral Canyon County Sun Valley Lateral Idaho Falls Lateral
Year
↓
Capacity
(th/day) Enhancement
Selected
Capacity
(th/day) Enhancement
Selected
Capacity
(th/day) Enhancement
Selected
Capacity
(th/day) Enhancement
Selected
Capacity
(th/day) Enhancement
Selected
2021 745,000 None 820,000 None 1,032,000
12-inch Ustick
Phase II 200,000 None 904,000 None
2022 870,000
12-inch S
Boise Loop 820,000 None 1,032,000 None 247,500
Compressor
Station 904,000 None
2023 870,000 None 950,000
Phase II
Uprate 1,390,000
12-inch Ustick
Phase III 247,500 None 1,093,000
IFL Compressor
Station
2024 870,000 None 950,000 None 1,390,000 None 247,500 None 1,093,000 None
2025 870,000 None 950,000 None 1,390,000 None 247,500 None 1,093,000 None
2026 870,000 None 950,000 None 1,390,000 None 247,500 None 1,093,000 None
Intermountain Gas Company
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Capacity Enhancements

Based on Table 16, the Company’s planning horizon provides sufficient time to identify, budget, plan,
design and construct projects to address capacity deficits. As part of the IRP process, Intermountain
will revisit the identified capacity deficits and alternatives considered for capacity enhancement in
its next IRP filling in 2023 and adjust its plan, as needed, to ensure reliable service to the Company’s
customers.
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Load Demand Curves

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)
2026 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 PY26 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 sendout 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.
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 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.
Intermountain Gas Company
I n t e g r a t e d R e s o u r c e P l a n 2 0 2 1 -2 0 2 6 119
Load Demand Curves

Customer Growth Summary Observations – Design Weather – All Scenarios
Idaho Falls Lateral
The Idaho Falls Lateral low growth scenario projects an increase in customers of 4,793 PY21 through
PY26 (Jan 1, 2021 to Dec 31, 2026) which corresponds to an annualized growth rate of 1.32%. In the
base case scenario customers are forecasted to increase by 9,493 (2.54% annualized growth rate),
while the high growth scenario forecasts an increase of 12,330 customers (3.24% annualized growth
rate).
Sun Valley Lateral
The Sun Valley Lateral low growth scenario (PY21 – PY26) projects an increase of 423 customers
(0.55% annualized growth rate). In the base case scenario customers are projected to increase by
1,262 (1.61% annualized growth rate), while the high growth scenario shows an increase of 1,976
customers (2.46% annualized growth rate).
Canyon County Area
The low growth customer forecast (PY21 – PY26) for Canyon County Area reflects an increase of
11,536 customers (3.08% annualized growth rate). In the base case scenario customers are
forecasted to increase by 15,324 (4.00% annualized growth rate), while the high growth scenario
projects an increase of 21,038 customers (5.31% annualized growth rate).
State Street Lateral
The low growth customer forecast (PY21 – PY26) for the State Street Lateral reflects an increase of
6,039 customers (1.70% annualized growth rate). The base case scenario projects an increase of
12,008 customers (3.25% annualized growth rate), while the high growth scenario forecasts an
increase of 17,977 customers (4.69% annualized growth rate).
Central Ada County
The low growth customer forecast (PY21 – PY26) for the Central Ada County reflects an increase of
6,026 customers (1.69% annualized growth rate). In the base case scenario customers are forecasted
to increase by 6,300 (1.77% annualized growth rate), while the high growth scenario projects an
increase of 6,574 customers (1.84% annualized growth rate).
Total Company
The Total Company (TC) low growth customer forecast (PY21 – PY26) projects an increase of 39,673
customers (1.64% annualized growth rate). The base case scenario forecasts an increase of 69,894
customers (2.80% annualized growth rate), while the high growth scenario projects an increase of
92,025 customers (3.62% 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.
Intermountain Gas Company
I n t e g r a t e d R e s o u r c e P l a n 2 0 2 1 -2 0 2 6 120
Load Demand Curves

Core Customer Distribution Sendout Summary – Design and Normal Weather – All Scenarios

Idaho Falls Lateral

Idaho Falls Design Weather - Annual Core Market Distribution Sendout (Dth)
Growth
Scenario 2021 2022 2023 2024 2025 2026
7,313,723 7,393,050 7,467,578 7,538,923 7,591,011 7,603,492
7,330,393 7,548,555 7,709,736 7,864,706 7,989,242 8,100,127
7,332,838 7,577,888 7,794,859 8,011,007 8,206,853 8,389,385

Idaho Falls Normal Weather - Annual Core Market Distribution Sendout (Dth)
Growth
Scenario 2021 2022 2023 2024 2025 2026
6,310,642 6,376,739 6,436,739 6,493,082 6,529,576 6,530,147
6,325,284 6,510,959 6,645,887 6,774,348 6,873,508 6,958,959
6,327,432 6,536,445 6,719,460 6,900,777 7,061,442 7,208,740
Intermountain Gas Company
I n t e g r a t e d R e s o u r c e P l a n 2 0 2 1 -2 0 2 6 121
Load Demand Curves

Sun Valley Lateral
Scenario 2021 2022 2023 2024 2025 2026
2,317,982 2,325,822 2,334,490 2,341,042 2,341,667 2,338,517
2,323,078 2,370,563 2,402,427 2,433,267 2,458,832 2,474,391
2,324,946 2,389,141 2,443,139 2,496,617 2,545,395 2,584,595

Sun Valley Normal Weather - Annual Core Market Distribution Sendout (Dth)
Growth
Scenario 2021 2022 2023 2024 2025 2026
1,949,889 1,956,046 1,962,477 1,966,853 1,965,431 1,960,246
1,953,961 1,993,534 2,019,518 2,044,322 2,063,899 2,074,458
1,955,454 2,009,066 2,053,657 2,097,508 2,136,610 2,167,055

Canyon County Area
Scenario 2021 2022 2023 2024 2025 2026
7,217,073 7,450,502 7,688,923 7,912,084 8,096,459 8,253,084
7,234,310 7,627,230 7,911,261 8,198,271 8,468,104 8,678,267
7,240,200 7,696,801 8,070,845 8,499,019 8,897,187 9,255,869

Canyon County Normal Weather - Annual Core Market Distribution Sendout (Dth)
Growth
Scenario 2021 2022 2023 2024 2025 2026
5,570,583 5,746,227 5,922,908 6,087,259 6,218,398 6,326,719
5,583,487 5,882,344 6,094,568 6,308,215 6,505,278 6,655,038
5,587,896 5,935,942 6,217,646 6,540,228 6,836,449 7,100,871
Intermountain Gas Company
I n t e g r a t e d R e s o u r c e P l a n 2 0 2 1 -2 0 2 6 122
Load Demand Curves

State Street Lateral
State Street Design Weather - Annual Core Market Distribution Sendout (Dth)
Growth
Scenario 2021 2022 2023 2024 2025 2026
7,334,413 7,429,544 7,517,954 7,625,128 7,710,794 7,763,896
7,345,613 7,557,350 7,763,234 7,976,172 8,184,892 8,398,836
7,356,812 7,685,157 8,008,514 8,327,217 8,658,989 9,033,776

State Street Normal Weather - Annual Core Market Distribution Sendout (Dth)
Growth
Scenario 2021 2022 2023 2024 2025 2026
5,656,133 5,723,436 5,782,335 5,855,320 5,908,973 5,936,781
5,664,500 5,821,816 5,971,390 6,126,088 6,274,665 6,426,521
5,672,867 5,920,196 6,160,446 6,396,857 6,640,356 6,916,261

Central Ada County
Scenario 2021 2022 2023 2024 2025 2026
7,341,834 7,420,571 7,526,646 7,620,523 7,696,622 7,792,613
7,345,106 7,451,591 7,548,554 7,647,021 7,736,397 7,825,454
7,348,378 7,482,610 7,570,462 7,673,519 7,776,171 7,858,295

Central Ada Normal Weather - Annual Core Market Distribution Sendout (Dth)
Growth
Scenario 2021 2022 2023 2024 2025 2026
5,662,622 5,718,077 5,791,755 5,855,929 5,903,778 5,966,307
5,665,067 5,741,949 5,808,695 5,876,377 5,934,445 5,991,679
5,667,511 5,765,820 5,825,636 5,896,825 5,965,113 6,017,051
Intermountain Gas Company
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Load Demand Curves

Total Company
Total Company Design Weather - Annual Core Market Distribution Sendout (Dth)
Growth
Scenario 2021 2022 2023 2024 2025 2026
50,028,542 50,613,073 51,242,752 51,880,441 52,413,238 52,886,679
50,132,521 51,677,636 52,898,239 54,132,992 55,254,789 56,254,884
50,175,415 52,128,464 53,689,357 55,364,769 56,992,544 58,583,685

Total Company Normal Weather - Annual Core Market Distribution Sendout (Dth)
Growth
Scenario 2021 2022 2023 2024 2025 2026
40,246,788 40,686,882 41,145,192 41,606,486 41,964,189 42,266,236
40,329,618 41,542,427 42,477,389 43,419,467 44,251,028 44,977,296
40,363,787 41,904,858 43,114,099 44,410,853 45,649,638 46,851,454

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 sendout 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 PY25.

Idaho Falls Design Weather - Peak Day Deficit Under Existing Resources (Dth)
Growth Scenario 2021 2022 2023 2024 2025 2026
Low 0 0 0 0 0 0
Base 0 0 0 0 379 1,806
High 0 0 0 338 3,526 5,615
Intermountain Gas Company
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Load Demand Curves

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 PY21-PY26 under the base case scenario.

Sun Valley Design Weather - Peak Day Deficit Under Existing Resources (Dth)
Growth Scenario 2021 2022 2023 2024 2025 2026
Low 327 397 344 430 118 171
Base 341 744 1,018 1,295 1,569 1,765
High 347 926 1,427 1,902 2,401 2,804

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.

Canyon County Design Weather - Peak Day Deficit Under Existing Resources (Dth)
Growth Scenario 2021 2022 2023 2024 2025 2026
Low 0 0 0 0 0 1,435
Base 0 0 0 178 3,143 5,507
High 0 0 0 3,952 8,111 11,898

Intermountain Gas Company
I n t e g r a t e d R e s o u r c e P l a n 2 0 2 1 -2 0 2 6 125
Load Demand Curves

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 PY26 under the base case scenario.

State Street Design Weather - Peak Day Deficit Under Existing Resources (Dth)
Growth Scenario 2021 2022 2023 2024 2025 2026
Low 0 0 0 0 0 0
Base 0 0 0 0 0 604
High 0 0 0 0 2,592 6,586

Central Ada County LDC Study
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 PY24-PY26 under the base case scenario.

Central Ada Design Weather - Peak Day Deficit Under Existing Resources (Dth)
Growth Scenario 2021 2022 2023 2024 2025 2026
Low 0 0 0 0 769 2,045
Base 0 0 0 84 1,262 2,452
High 0 0 0 373 1,706 2,809

Intermountain Gas Company
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Load Demand Curves

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 only peak day deficits based on
existing resources in the year of 2026 due to the amount of transportation expiring. The solution for this
shortfall is discussed further in the Upstream Modeling Results portion of the Planning Results section.

Total Company Design Weather - Peak Day SENDOUT (Core+LV-1) Deficit Under Existing Resources (Dth)
Scenario 2021 2022 2023 2024 2025 2026
0 0 0 0 0 10,828
0 0 0 0 0 42,147
0 0 0 0 0 63,449

2019 IRP vs. 2021 IRP Common Year Comparisons
This section compares the Total Company and each AOI during the three common years of the 2021 and 2019
IRP filings. In some cases, the distribution transportation capacity is forecast to be lower in the 2021 IRP than
it was in the 2019 IRP. This is the result of differences in, or fine tuning of, planned capacity upgrades.

Total Company Design Weather/ Base Case Growth Comparison

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

Core

Firm CD1

Total

457,525 140,364 597,889
472,744 140,779 613,523
485,297 141,379 626,676
1Existing firm contract demand includes LV-1 and T-4 requirements.

Intermountain Gas Company
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Load Demand Curves

2019 IRP LOAD DEMAND CURVE – TC USAGE DESIGN BASE CASE (Dth)

Core
Peak Day Sendout

Firm CD1

Total

2021 466,361 146,729 613,090
2022 481,569 147,522 629,091
496,500 148,830 645,330
1Existing firm contract demand includes LV-1 and T-4 requirements.

2021 IRP LOAD DEMAND CURVE – TC USAGE DESIGN BASE CASE
Over/(Under) 2019 IRP (Dth)

Core

Peak Day Sendout

Firm CD1

Total

2021 (8,836) (6,365) (15,201)
(8,825) (6,743) (15,568)
(11,203) (7,451) (18,654)
1Existing firm contract demand includes LV-1 and T-4 requirements.
Intermountain Gas Company
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Load Demand Curves

Total Company Peak Day Deliverability Comparison

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
341,043 341,043 332,043
586,555 586,555 577,555

2019 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
297,043 297,043 297,043
542,555 542,555 542,555
Intermountain Gas Company
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Load Demand Curves

2021 IRP PEAK DAY FIRM DELIVERY CAPABILITY
Over/(Under) 2019 (Dth)

Maximum Daily Storage Withdrawals:
Nampa LNG 0 0 0
Plymouth LS 0 0 0
Jackson Prairie SGS 0 0 0
0 0 0
44,000 44,000 35,000
44,000 44,000 35,000

Idaho Falls Lateral Design Weather/Base Case Growth Comparison

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

Distribution

Core

Peak Day Sendout

Firm CD1

Total

2021 90,400 62,926 21,281 84,207
90,400 64,937 21,281 86,218
2023 109,300 66,479 21,331 87,810

1Existing firm contract demand includes LV-1 and T-4 requirements.
Intermountain Gas Company
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Load Demand Curves

2019 IRP LOAD DEMAND CURVE – IFL USAGE DESIGN BASE CASE (Dth)

Distribution

Core

Peak Day Sendout

Firm CD1

Total

88,400 63,154 21,469 84,623
88,400 64,940 21,464 86,404
2023 94,000 66,728 21,681 88,409

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

2021 IRP LOAD DEMAND CURVE – IFL USAGE DESIGN BASE CASE
Over/(Under) 2019 IRP (Dth)

Distribution
Transport Capacity

Core
Market

Peak Day Sendout

Firm CD1

Total

2021 2,000 (228) (188) (416)
2,000 (3) (183) (186)
15,300 (249) (350) (599)

1Existing firm contract demand includes LV-1 and T-4 requirements.
Intermountain Gas Company
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Load Demand Curves

Sun Valley Lateral Design Weather/ Base Case Growth Comparison

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

Distribution
Transport Capacity

Core
Market

Peak Day Sendout

Firm CD1

Total

20,000 18,406 1,935 20,341
24,750 18,809 1,935 20,744
24,750 19,083 1,935 21,018

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

2019 IRP LOAD DEMAND CURVE –SVL USAGE DESIGN BASE CASE (Dth)

Distribution
Transport Capacity

Core
Market

Firm CD1

Total

22,000 18,704 1,395 20,099
22,000 19,114 1,395 20,509
22,000 19,519 1,380 20,899

1Existing firm contract demand includes LV-1 and T-4 requirements.
Intermountain Gas Company
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Load Demand Curves

2021 IRP LOAD DEMAND CURVE –SVL USAGE DESIGN BASE CASE
Over/(Under) 2019 (Dth)

Distribution

Core

Peak Day Sendout

Firm CD1

Total

(2,000) (298) 540 242
2022 2,750 (305) 540 235
2,750 (436) 555 119

1Existing firm contract demand includes LV-1 and T-4 requirements.
Intermountain Gas Company
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Load Demand Curves

Canyon County Area Design Weather/ Base Case Growth Comparison

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

Distribution
Transport Capacity

Core
Market

Peak Day Sendout

Firm CD1

Total

103,200 68,791 24,740 93,531
103,200 72,756 24,790 97,546
139,000 75,629 24,790 100,419

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

2019 IRP LOAD DEMAND CURVE – CCA USAGE DESIGN BASE CASE (Dth)

Distribution
Transport Capacity

Core
Market

Firm CD1

Total

98,000 70,339 25,218 95,557
106,000 74,041 25,245 99,286
106,000 77,818 25,268 103,086

1Existing firm contract demand includes LV-1 and T-4 requirements.
Intermountain Gas Company
I n t e g r a t e d R e s o u r c e P l a n 2 0 2 1 -2 0 2 6 134
Load Demand Curves

2021 IRP LOAD DEMAND CURVE – CCA USAGE DESIGN BASE CASE
Over/(Under) 2019 (Dth)

Distribution

Core

Peak Day Sendout

Firm CD1

Total

5,200 (1,548) (478) (2,026)
2022 (2,800) (1,285) (455) (1,740)
33,000 (2,189) (478) (2,667)

1Existing firm contract demand includes LV-1 and T-4 requirements.
Intermountain Gas Company
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Load Demand Curves

State Street Lateral Design Weather/ Base Case Growth Comparison

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

Distribution
Transport Capacity

Core
Market

Peak Day Sendout

Firm CD1

Total

82,000 70,114 990 71,104
82,000 72,284 990 73,274
95,000 74,518 990 75,508

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

2019 IRP LOAD DEMAND CURVE – SSL USAGE DESIGN BASE CASE (Dth)

Distribution
Transport Capacity

Core
Market

Firm CD1

Total

73,000 68,146 1,220 69,366
73,000 69,973 1,220 71,193
77,000 71,850 1,220 73,070

1Existing firm contract demand includes LV-1 and T-4 requirements.
Intermountain Gas Company
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Load Demand Curves

2021 IRP LOAD DEMAND CURVE – SSL USAGE DESIGN BASE CASE
Over/(Under) 2019 (Dth)

Distribution

Core

Peak Day Sendout

Firm CD1

Total

9,000 1,968 (230) 1,738
2022 9,000 2,311 (230) 2,081
18,000 2,668 (230) 2,438

1Existing firm contract demand includes LV-1 and T-4 requirements.
Intermountain Gas Company
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Load Demand Curves

Central Ada County Design Weather/ Base Case Growth Comparison

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

Distribution
Transport Capacity

Core
Market

Peak Day Sendout

Firm CD1

Total

74,500 70,145 850 70,995
87,000 71,295 950 72,245
87,000 72,457 950 73,407

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

2019 IRP LOAD DEMAND CURVE – CAC USAGE DESIGN BASE CASE (Dth)

Distribution

Core

Firm CD1

Total

2021 70,000 67,932 1,448 69,380
78,000 69,645 1,485 71,130
78,000 71,401 1,530 72,931

1Existing firm contract demand includes LV-1 and T-4 requirements.
Intermountain Gas Company
I n t e g r a t e d R e s o u r c e P l a n 2 0 2 1 -2 0 2 6 138
Load Demand Curves

2021 IRP LOAD DEMAND CURVE – CAC USAGE DESIGN BASE CASE
Over/(Under) 2019 (Dth)

Distribution

Core

Peak Day Sendout

Firm CD1

Total

4,500 2,213 (598) 1,615
2022 9,000 1,650 (535) 1,115
9,000 1,056 (580) 476

1Existing firm contract demand includes LV-1 and T-4 requirements.
I n t e g r a t e d R e s o u r c e P l a n 2 0 2 1 -2 0 2 6 139
Resource Optimization Intermountain Gas Company

Resource Optimization

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, 2021 to 2026.
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.

Functional Components of the Model
The optimization model has the following functional components:
• Demand Forecast by AOI
• Supply Resources, Storage and Supply, by Area
• Transportation Capacity Resources, Local Laterals and Major Pipelines, Between Areas
• Non-Traditional Resources such as Renewable Natural Gas
• Demand Side Management

Underlying these functional components is a model structure that has gas supply and demand by
area of interest with gas transported by major pipelines and local distribution laterals between
supply and demand. This model mirrors, in general, how Intermountain’s delivery system
contractually and operationally functions. In previous IRPs, Intermountain utilized Boris Metrics
to perform the optimization modeling. Beginning with 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.

Demand SENDOUT® 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 is
a computer optimization model known as SENDOUT®.

I n t e g r a t e d R e s o u r c e P l a n 2 0 2 1 -2 0 2 6 140
Resource Optimization Intermountain Gas Company

SENDOUT® 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. SENDOUT® permits
the Company to develop and analyze a variety of resource portfolios quickly and to determine
the type, size, and timing of resources best matched to forecast requirements.

Model Structure
To develop a basic understanding of how gas supply flows from the various receipt points to
ultimate delivery to the Company’s end-use customers, a graphical representation of
Intermountain’s system is helpful. Figure 2 (page 6) is a map of the Intermountain system.
Generally, gas flows from supply areas such as Canada and the Rockies, and from storage in
Washington state and Clay Basin in the Rockies region, across major pipelines to southern Idaho.
In southern Idaho, the gas is transported to demand areas by local distribution laterals. The
model utilizes a simplified structure of the Figure 2 map.
Figure 58 presents the model of system flows by major pipelines and supply areas. The Figure
also shows four major supply receipt areas including Sumas, Stanfield, AECO and Rockies with
ultimate delivery to Intermountain in southern Idaho.

Figure 58: 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 58.
I n t e g r a t e d R e s o u r c e P l a n 2 0 2 1 -2 0 2 6 141
Resource Optimization Intermountain Gas Company

Demand Area Forecasts
As previously discussed in the Load Demand Curves Section beginning on page 118, 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 457,525 dth for RS (Residential) and GS
(commercial) customers and 140,364 dth for LV-1 and T-4 customers in 2021 and growing to
522,487 dth and 143,374 dth in 2026, respectively.
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Figure 59: IGC Laterals from Zone 24
The demand areas listed in Figure 59 are:

• Central Ada Area
• State Street Lateral
• Canyon County Region
• Idaho Falls Lateral
• Sun Valley Lateral
• All Other
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Figure 60: Total Company Design Base 2021
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 60 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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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
61 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 61: IGC Supply Model Example

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Figure 62: IGC Storage Model Example

Figure 62 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 63
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 81).

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Figure 63: IGC DSM Model Example
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 SENDOUT®’s transportation model is seen
in Figure 64.
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Figure 64: IGC Transport Model Example
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 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
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least cost present value optimization, to approximate the expected total costs for transport and
supply.

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.

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 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.
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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. Figure 65 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.

Figure 65: Transport Input Summary

The price forecast is provided in the Traditional Supply Resources section.

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Model Results
The optimization model results for the design weather, base price and base case scenario for the
years 2021 through 2026 are presented and discussed below. The results of the model are
summarized, for each scenario using the tables described below:

• Upstream Transportation and Lateral Summary Tables (Exhibit 9)
• Annual Transportation Resources Results (Exhibit 8)
• Annual Supply Resources Results (Exhibit 8)

Model Output for Design Base Scenario
The following provides a description of the information presented by type of output tables in
Exhibit 9 and the implication for the Design Base scenario.
Exhibit 9 provides a snapshot by year of whether a specific lateral to an AOI needs an expansion
and whether that expansion is a preferred one as opposed to a fill or an alternative lateral
resource. Figure 66 shows the first year of the Upstream Transportation and Lateral Summary,
for the Design Base scenario.
The “Total Peak Day” is the peak day that includes RS, GS, LV-1, and T-4 customers, since the
distribution system must maintain reliability for these customers. The “Existing Capacity” column
is the amount of deliverability Intermountain has on the distribution system for each area of
interest. The “% of Existing Capacity” is the percentage of total peak day compared to existing
capacity. The “Existing + Upgrade Capacity” column is the amount of deliverability Intermountain
has on the distribution system for each area of interest after the upgrades discussed in the
Capacity Enhancements section take place. The “% of Existing + Upgrade Capacity” is the
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).
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Figure 66: Lateral Summary by Year
Figure 67 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.

Figure 67: Annual Traditional Supply Resources Results

The supply resources in the detailed output tables have the following output parameters:
• Total Commodity Cost by year
• Monthly Supply by basin and type of Supply
• Unit Commodity Cost

The total commodity cost is the total dollar amount spent on gas purchased at the supply group
location on an annual basis. The monthly supply is the amount of gas purchased at the supply
group. The unit commodity cost is the dollar per dekatherm that was spent on purchasing the
gas at each supply location. Exhibit 8 also includes the daily purchase amount by supply location
for design day.

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A sample of the Annual Transportation Resources Results from Exhibit 8 for the Design Base
scenario is displayed Figure 68. Exhibit 8 also provides transportation results by month for the
planning horizon.

Figure 68: Annual Transportation Resources Results

The transportation resources in the detailed output tables have the following output parameters:
• D1 Cost
• Outflow
• Transportation Cost

The D1 cost is the total dollars spent on the transportation contracts based on the pipelines. The
outflow is the actual amount of gas that flowed on the associated transport group and the
transportation costs are the total dollars spent on the transportation rate. Exhibit 8 also includes
the outflow on design day.

Other Scenarios
Upstream Transportation and Lateral Summary tables for the high and low customer growth as
well as normal weather are provided in Exhibit 10. One notable result from the other scenarios
is that even under the most extreme scenario, design weather with high growth, there is still
sufficient upstream transportation and distribution system capacity to serve customers through
the planning horizon when including the planned solutions for shortfalls in the Planning Results
chapter.

Summary
In summary, the optimization model employs utility standard practice method to optimize
Intermountain’s system via linear programming through SENDOUT®. The optimization includes
DSM as a decrement to demand and also optimizes storage injections and withdrawals across
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seasons. An analysis on lateral expansion is performed as well as an analysis to check for any
shortfalls in upstream transportation or supply capacity.
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Planning Results

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 2021 and 2019 IRP filings. Finally, the planning results for upstream
transportation shortfalls are discussed.

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 options chosen were the Ustick Phase
II and Ustick Phase III enhancements.
The following graph (Figure 69) shows no deficit in the final year of the planning horizon under
the base case scenario after completion of the proposed capacity upgrades.

Figure 69: LDC Design Base Case – Canyon County Lateral

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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 70) shows no deficit in the final year of the planning horizon under
the base case scenario after completion of the proposed capacity upgrade.

Figure 70: 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 71) shows no deficit in the final year of the planning horizon under
the base case scenario after completion of the proposed capacity upgrade.

Figure 71: 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, 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
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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 72) shows no deficit in the final year of the planning horizon under
the base case scenario after completion of the proposed capacity upgrade.

Figure 72: LDC Design Base Case – Sun Valley Lateral

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 73) 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 73: LDC Design Base Case – Idaho Falls Lateral
2019 IRP vs. 2021 IRP Common Year Comparisons
This section compares any firm delivery deficits for Total Company and each AOI during the three
common years of the 2021 and 2019 IRP filings.
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Total Company Peak Delivery Deficit Comparison

2021 IRP FIRM DELIVERY DEFICIT – TC DESIGN BASE CASE (Dth)

Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0

1Equal to the total winter sendout in excess of interstate capacity less total "peaking" storage. Peaking storage does not require the use of

2019 IRP FIRM DELIVERY DEFICIT – TC DESIGN BASE CASE (Dth)

Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0

1Equal to the total winter sendout in excess of interstate capacity less total "peaking" storage. Peaking storage does not require the use of

2021 IRP FIRM DELIVERY DEFICIT – TC DESIGN BASE CASE
Over/(Under) 2019 (Dth)

Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0

1Equal to the total winter sendout in excess of interstate capacity less total "peaking" storage. Peaking storage does not require the use of

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Idaho Falls Lateral Peak Delivery Deficit Comparison

2021 IRP FIRM DELIVERY DEFICIT – IFL DESIGN BASE CASE (Dth)

Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0

1Equal to the total winter sendout in excess of distribution capacity.

2019 IRP FIRM DELIVERY DEFICIT – IFL DESIGN BASE CASE (Dth)

Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0

1Equal to the total winter sendout in excess of distribution capacity.

2021 IRP FIRM DELIVERY DEFICIT – IFL DESIGN BASE CASE
Over/(Under) 2019 (Dth)

Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0

1Equal to the total winter sendout in excess of distribution capacity.

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Sun Valley Lateral Delivery Deficit Comparison

2021 IRP FIRM DELIVERY DEFICIT – SVL DESIGN BASE CASE (Dth)

Peak Day Deficit 341 0 0
Total Winter Deficit1 341 0 0
Days Requiring Additional Resources 1 0 0

1Equal to the total winter sendout in excess of distribution capacity.

2019 IRP FIRM DELIVERY DEFICIT – SVL DESIGN BASE CASE (Dth)

Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0

1Equal to the total winter sendout in excess of distribution capacity.

2021 IRP FIRM DELIVERY DEFICIT – SVL DESIGN BASE CASE
Over/(Under) 2019 (Dth)

Peak Day Deficit 341 0 0
Total Winter Deficit1 341 0 0
Days Requiring Additional Resources 1 0 0

1Equal to the total winter sendout in excess of distribution capacity.

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Canyon County Area Delivery Deficit Comparison

2021 IRP FIRM DELIVERY DEFICIT – CCA DESIGN BASE CASE (Dth)

Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0

1Equal to the total winter sendout in excess of distribution capacity.

2019 IRP FIRM DELIVERY DEFICIT – CCA DESIGN BASE CASE (Dth)

Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0

1Equal to the total winter sendout in excess of distribution capacity.

2021 IRP FIRM DELIVERY DEFICIT – CCA DESIGN BASE CASE
Over/(Under) 2019 (Dth)

Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0

1Equal to the total winter sendout in excess of distribution capacity.

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State Street Lateral Firm Delivery Deficit Comparison

2021 IRP FIRM DELIVERY DEFICIT – SSL DESIGN BASE CASE (Dth)

Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0

1Equal to the total winter sendout in excess of distribution capacity.

2019 IRP FIRM DELIVERY DEFICIT – SSL DESIGN BASE CASE (Dth)

Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0

1Equal to the total winter sendout in excess of distribution capacity.

2021 IRP FIRM DELIVERY DEFICIT – SSL DESIGN BASE CASE
Over/(Under) 2019 (Dth)

Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0

1Equal to the total winter sendout in excess of distribution capacity.

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Central Ada County Firm Delivery Deficit Comparison

2021 IRP FIRM DELIVERY DEFICIT – CAC DESIGN BASE CASE (Dth)

Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0

1Equal to the total winter sendout in excess of distribution capacity.

2019 IRP FIRM DELIVERY DEFICIT – CAC DESIGN BASE CASE (Dth)

Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0

1Equal to the total winter sendout in excess of distribution capacity.

2021 IRP FIRM DELIVERY DEFICIT – CAC DESIGN BASE CASE
Over/(Under) 2019 (Dth)

Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0

1Equal to the total winter sendout in excess of distribution capacity.

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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 City Gate Delivery declines beginning
in 2023 as upstream transportation contracts begin to expire. Due to expiring contracts,
Intermountain does show a shortfall in the final year of the planning horizon. The following graph
(Figure 74) shows the shortfall created by expiring contracts.

Figure 74: 2026 Design Base Case – Total Company

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.
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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
not to renew some contracts. With that said, the model also picked up about 6,000 dth a day of
incremental GTN 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.

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.
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Non-Utility LNG Forecast

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.
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.

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.
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Method of Forecasting
Intermountain utilized the results of the supply study (see Load Demand Curves starting on page
118) 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 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. The table below 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 17: Nampa LNG Inventory Available for Non-Utility Sales
Nampa LNG Inventory Available for Non-Utility Sales

Gallons

2022

2023

2024

2025

2026
Projected Withdrawal (High Growth) 0 0 1,282,682 2,248,848 2,240,988
Annual Boil-off 1,200,000 1,200,000 1,200,000 1,200,000 1,200,000
Permanent Inventory 500,000 500,000 500,000 500,000 500,000
Nampa & Rexburg Requirements 300,000 300,000 300,000 300,000 300,000
Net Utility Requirement 2,000,000 2,000,000 3,282,682 4,248,848 4,240,988
Available for Non-utility Sales 5,000,000 5,000,000 3,717,318 2,751,152 2,759,012

Benefits to Customers
Intermountain’s customers benefit from Intermountain’s LNG sales activities in several different
ways. First, Intermountain continues to defer 2.5¢ 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
of 2.5¢ per gallon sold as an offset to increased operating and maintenance costs as a result of
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non-utility sales. 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 35 million gallons of LNG to non-utility
customers. These sales have provided nearly $880,000 to offset increased capital costs.
Additionally, through its PGA the Company has credited to its utility customers approximately
$880,000 to offset increased O&M costs and nearly $4.6 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.

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.

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 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,
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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.

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.

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 affect on
margins once the tank is back in service. 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
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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.

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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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.

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 recommended for replacement in
2022. 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.

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 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.
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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.

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 (SME’s) 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.

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.

Risk Score = 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.

Risk Ratio = ∑ (Total Relative Risk Score x Pipe Length) / ∑ Pipe Length
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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 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 within the distribution
system. In 2020 Intermountain started SSIP replacement in St. Anthony, ID which continued
into 2021, and is anticipated to be completed in 2022. After St. Anthony, Intermountain will be
moving to the next highest risk system based on the risk prioritization. Intermountain currently
has approximately $3.6 (2021) – $4.4 (2025) 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
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Glossary

Agent (Marketer)
A legal representative of buyers, sellers or shippers of natural gas in negotiation or operations of
contractual agreements.
All Other Customers Segment (All Other)
All other segments of the Company’s distribution system serving core market customers in Ada
County not included in the State Street Lateral or Central Ada County, as well as customers in
Bannock, Bear Lake, Caribou, Cassia, Elmore, Gem, Gooding, Jerome, Minidoka, Owyhee,
Payette, Power, Twin Falls, and Washington counties; an Area of Interest for Intermountain.
Area of Interest (AOI)
Distinct segments within Intermountain’s current distribution system.
British Thermal Unit (BTU)
The amount of heat that is necessary to raise the temperature of one pound of water by 1 degree
Fahrenheit
Bundled Service
Gas sales service and transportation service packaged together in a single transaction in which
the utility, on behalf of the customer, buys gas from producers and then transports and delivers
it to the customer.
Canyon County Area (CCA)
A distinct segment of Intermountain’s distribution system which serves core market customers
in Canyon County; an Area of Interest for Intermountain.
Central Ada County (CAC)
Multiple high-pressure pipeline systems which serve core market customers in Ada County
between Chinden Boulevard and Victory Road, north to south, and between Maple Grove Road
and Black Cat Road, east to west; an Area of Interest for Intermountain.
Citygate
The points of delivery between the interstate pipelines providing service to the utility or the
location(s) at which custody of gas passes from the pipeline to the utility.
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.
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Contract Demand (CD)
The maximum peak day amount of distribution capacity that Intermountain guarantees to
reserve for a firm customer each day. The amount is specified in the customer contract. Also see
MDFQ.
Core Market
All residential and commercial customers of Intermountain Gas Company. Includes all customers
receiving service under the RS and GS tariffs.
Customer Management Module (CMM)
A software product, provided by DNV as part of their Synergi Gas product line, to analyze natural
gas usage data and predict usage patterns on an individual customer level.
Delivery (Receipt Point)
Designated points where natural gas is transferred from one party to another. Receipt points are
those locations where a local distribution company delivers, and an interstate pipeline receives,
gas supplies for re-delivery to the local distribution company’s city gates.
Design Year
An estimate of the highest level of annual customer demand that may occur, incorporating
extreme cold or peak weather events; a measure used for planning capacity requirements.
Design Weather
Heating degree days that represent the coldest temperatures that may occur in the IGC service
territory.
Direct Use
The use of natural gas at the point of final heating energy use, such as natural gas space heating,
water heating, cooking, and other heating uses, as opposed to burning natural gas in a power
plant to generate electricity to be used at the point(s) of use to for site space heat, water heat,
cooking heat and other heat applications. Direct use is a much more efficient use of natural gas.
Demand Side Management (DSM)
Programs implemented by the Company and utilized by its customers to influence the amount
and timing of natural gas consumption.
Electronic Bulletin Board (EBB)
A generic name for the system of electronic posting of pipeline transmission information as
mandated by FERC.

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FERC - Federal Energy Regulatory Commission
The federal agency that regulates interstate gas pipelines and interstate gas sales under the
Natural Gas Act. Successor to the Federal Power Commission, the FERC is considered an
independent regulatory agency responsible primarily to Congress, but it is housed in the
Department of Energy.
Firm Customer
A customer receiving service under rate schedules or contracts designed to provide the
customer's gas supply and distribution needs on a continuous basis, even on a peak day.
Firm Service
A service offered to customers under schedules or contracts which anticipate no interruptions.
Fixed Physical
A fixed forward (also known as a fixed price physical contract) is an agreement between two
parties to buy or sell a specified amount of natural gas at a certain future time, at a specific price,
which is agreed upon at the time the deal is executed. It operates much like the price swap
without the margin call risk.
Formation
A formation refers to either a certain layer of the earth's crust, or a certain area of a layer. It often
refers to the area of rock where a petroleum or other hydrocarbon reservoir is located. Other
related terms are basin or play.
Gas Transmission Northwest (GTN)
A U.S. pipeline which begins at the U.S.-Canadian border near Kingsgate, British Columbia and
interconnects with Williams Northwest Pipeline at the Stanfield receipt point in Oregon.
Heating Degree Day (HDD)
An industry-wide standard, measuring how cold the weather is based on the extent to which the
daily mean temperature falls below a reference temperature base, which for IGC, is 65 degrees
Fahrenheit.
Idaho Falls Lateral (IFL)
A distinct segment of Intermountain’s distribution system which serves core market customers
in Bingham, Bonneville, Fremont, Jefferson, and Madison counties; an Area of Interest for
Intermountain.
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.
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Institutional Customer
For purposes of categorizing large volume customers, this would include business such as
hospitals, schools, and other weather sensitive customers.
Interruptible Customer
A customer receiving service under rate schedules or contracts which permit interruption of
service on short notice due to insufficient gas supply or capacity.
Interruptible Service
Lower-priority service offered to customers under schedules or contracts which anticipate and
permit interruption on short notice, generally in peak-load seasons, by reason of the higher
priority claim of firm service customers and other higher priority users. Service is available at any
time of the year if distribution capacity and/or pressure is sufficient.
Large Volume Customer
Any customer receiving service under one of the Company’s large volume tariffs including LV-1,
T-3, and T-4. Such service requires the customer to sign a minimum one-year contract and use at
least 200,000 therms per contract year.
Liquefied Natural Gas (LNG)
Natural gas which has been liquefied by reducing its temperature to minus 260 degrees
Fahrenheit at atmospheric pressure. In volume, it occupies one-six-hundredth of that of the
vapor at standard conditions.
Load Demand Curve (LDC)
A forecast of daily gas demand using design or normal temperatures, and predetermined usage
per customer.
Local Distribution Company
A retail gas distribution company, utility, that delivers retail natural gas to end users.
Lost and Unaccounted for Natural Gas (LAUF)
The difference between volumes of natural gas delivered to Intermountain’s distribution system
and volumes of natural gas billed to Intermountain’s customers.
Maximum Daily Firm Quantity (MDFQ)
The contractual amount that Intermountain guarantees to deliver to the customer each day. Also
see Contract Demand.

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Methane
Methane is commonly known as natural gas (or CH4) and is the most common of the hydrocarbon
gases. It is colorless and naturally odorless and burns efficiently without many by products.
Natural gas only has an odor when it enters a customer’s home because the local distributor adds
it as a safety measure.
Normal Weather
Normal weather is comprised of HDD’s that represent the average mean temperature for each
day of the year. Intermountain’s Normal Weather is a 30-year rolling average of NOAA’s daily
mean temperature.
Northwest Pipeline (Williams Northwest Pipeline, Northwest, NWP)
A 3,900-mile, bi-directional transmission pipeline crossing the states of Washington, Oregon,
Idaho, Wyoming, Utah and Colorado and the only interstate pipeline which interconnects to
Intermountain’s distribution system; all gas supply received by the Company is transported by
this pipeline.
NYMEX Futures
New York Mercantile Exchange is the world’s largest physical commodity futures exchange.
Futures are financial contracts obligating the buyer to purchase an asset (or the seller to sell an
asset), such as a physical commodity, at a predetermined future date and price. Futures contracts
detail the quality and quantity of the underlying asset; they are standardized to facilitate trading
on a futures exchange. Some futures contracts may call for physical delivery of the asset, while
others are settled in cash.
Peak Shaving
Using sources of energy, such as natural gas from storage, to supplement the normal amounts
delivered to customers during peak-use periods. Using these supplemental sources prevents
pipelines from having to expand their delivery facilities just to accommodate short periods of
extremely high demand.
Peak Day
The coldest day of the design year; a measure used for planning system capacity requirements.
For Intermountain, that day is currently January 15 of the design year.
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.

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Glossary Intermountain Gas Company

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.
SCADA (Supervisory Control and Data Acquisition)
Remote controlled equipment used by pipelines and utilities to operate their gas systems. These
computerized networks can acquire immediate data concerning flow, pressure or volumes of gas,
as well as control different aspects of gas transmission throughout a pipeline system.
State Street Lateral (SSL)
A distinct segment of Intermountain’s distribution system which serves core market customers
in Ada County north of the Boise River, bound on the west by Kingsbury Road west of Star, and
bound on the east by State Highway 21; an Area of Interest for Intermountain.
Sun Valley Lateral (SVL)
A distinct segment of Intermountain’s distribution system that serves customers in Blaine and
Lincoln counties; an Area of Interest for Intermountain.
Therm
A unit of heat energy equal to 100,000 British thermal units (BTU). It is approximately the energy
equivalent of burning 100 cubic feet (1 CCF) of natural gas.
Traffic Analysis Zones (TAZ)
An analysis of traffic patterns in certain high traffic areas.
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.

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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.