20251223Exhibit 1.pdf

Intermountain Gas Company
IGRAC Invite and Meeting Materials
2025 — 2030
INTEPAOUNTAIN `�'
GAS COMPANY
A Subsidiary of MDU Resources Group, Inc.
In the Community to Serve'
Exhibit No. 1

INTERMOUNTAIN
GAS COMPANY
A Subsidiary of MDU Resources Group, Inc.
INTEGRATED RESOURCE PLAN
DULY 9, 2025
INTERMOUNTAIN GAS RESOURCE ADVISORY COMMITTEE (IGRAC)

Welcome & Introductions — Brian Robertson
Safety Moment & Feedback Process — Brian Robertson
IRP Recommendations — Brian Robertson
System Overview — Brian Robertson
Economic Forecast— Ryan Denton
Residential & Commercial Customer Growth — Ryan
Vol — Denton
Design Heating Degree Days — Brian Robertson
Industrial Customer Forecasts — Nicole Gyllensl<og &
Jon Whiting
Load Demand Curves — Ryan Denton
Questions/Discussion
3

Introductions
Name
Organization you are representing
4

■
Blueprint to meet the Company's firm customer demands over a five-year forecast
period based on various assumptions
Provides frequent updates to the projected growth on the Company's system
Considers all available resources to meet the needs of the Company's customers on
a consistent and comparable basis
Solicits input from Stakeholders during the modeling process
Helps to ensure Intermountain Gas Company will continue to provide reliable
energy service while minimizing costs
5

INTERMOUNTAIN GAS COMPANY
Integrated Resource Plan Process
6

Demand Supply & Delivery Resources
(i Economic Overview - Transportation
1 Capacity & Storage Distribution Sys Ov tem
L
esidential & Commercial Overview
Customer Growth Natural Gas Supplies
Non-Traditional
Design Resources
Residential & Weather
Commercial Usage Energy Efficiency:
Per Customer --------------------=--- I Residential &
Commercial
Industrial Demand
Demand Supply & Deliverability
Load Demand Curves
Optimization Modeling
System
Enhancements
Demand Supply

SAFETY MOMENT
Preventing Eyestrain
The National Safety Council provided several tips to take to avoid strained and tired eyes.
• Keep your screen at arm's length.
• Don't forget to blink.
• Take a break every 20 minutes by looking away at something at least 20-feet away
for at least 20 seconds.
1 • Be mindful of lighting and glare.
• Make sure your screen isn't too bright.
• Adjust computer monitor properly.
• Increase your computer's type size.
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FEEDBACK SUBMISSIONS
■ [e-mail]
■ Please provide comments and feedback within 10 days
■ Intermountain IRPWebpage: https://www.intgas.com/rates-
services/rates-tariffs/integrated-resource-plan/
8
s

2023 IRP ACKNOWLEDGEMENT . IRP RECOMMENDATIONS
Final Order No. 36249 — Commission Acknowledged Intermountain's 2023 IRP Filing
Commission Recommendations for Intermountain's IRP Process:
Recommends the Company to work with Staff to implement IRP reporting that includes
system enhancement information in future IRPs, within six months of a Commission
order
Recommends the Company to work with Staff to develop reports to the Commission of
capacity enhancement projects that include in-service dates and project costs, within six
months of a Commission order
Establish the practice of authorizing the Company's DSM avoided costs as part of
IRP filings and authorize the DSM avoided costs associated with this filing.
10

SYSTEM OVERVIEW
BRIAN ROBERTSON
SUPERVISOR, RESOURCE PLANNING
11

INTERMOUNTAIN ♦ COMPANY
Intermountain Gas Company is a natural gas local
distribution company, founded in 1950 and served its
first customer in 1956
Provides service to 76 communities across southern
Idaho
433,400+ customers
12

THROUGHPUT BY CUSTOMER CLASS
Residential
36%
Large Volume
47%
Commercial
17%

INTERMOUNTAIN DISTRIBUTION
NATURAL GAS SYSTEM
INTERMOUNTAIN GAS COMPANY
WEBER oR[oo•r oNgo
RA.YETrE ui•
MUITLANO •cwo.
NEW PLYYOUTN •. - - , .u.• ST ANTIN)NY
MR KER••
EMaETT fUOAR CITY
Ml m • REXSURO•
f`I:NIDEfl• STAR. OMOEN CRY KETCNU�UN VALLEY LE"3
,_'�t7E1{eM
NO.EDALE•� • A\ #BOISE HAILEY \F R:09r•
NAMPA PoRIE
Kura• r-•�eELLEWE DAHO FALLS •10"1A
•AWCN
RRTN SHELLEY
Z•.
aoREL.Wo BAfALT
RNEtiiIDE=J•�OVEUHo
WIMAM"ME• r' �FCKFOOT
•PORT HALL.!� @OWMO arrDiNONE �� N/-CMl BUCK
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• wr.�aw..wo.. WRTAUON
I�w�/,../�wi.� "LT., �YOW"-EUE:.
14

AREAS OF INTEREST (AOI)
NATURAL GAS SYSTEM
INTERMOUNTAIN GAS COMPANY
CANADIAN GAS
■ Distribution System Segments. WASH' MONTANA
■ Canyon County WEISER OREGON
AREA- WYOMINO
OF MAP
PAYETTE ARKER S ANTHONY
■ Central Ada County Lateral FRUITLAND NEW PLVMOUT CALIF. NEVADA UTAH COLORADO BUDA CITY
FARM U.S.GAS REXBU G
MIDDLETON STAR�O� SAN UAN BASIN MENAN SATTELIT LNG
■ North of State Street Lateral WI \d ARDEN CITY EWISWLLE RIGBV
G ENLEAF,�, 9015E UN VALLEY
I�,%V Q CHUM/ELKHORN UCON`
■ Sun Valley Lateral P`O' U • ILEY AND FALLS• IONA`
AMMON 9iF m
T ELLEVUE SHELL
�O QQv FlRT BASALT 99
■ Idaho Falls Lateral MT.HOME ��y-,E MORRET HAD BLACKFOOT 0
O� Ap
GOODIN ABERDEEN HUBB 9Q¢�
S SHONE
■ All Other Customers WENDEL0 y0 gPfR/CgMFquS • P NKOM ,POPOeO
CONDA
BRUNEAU• 0�P OF'94'lpJ QP JOJq •SODA SPRINGS
BUHL MCCAMMON
LEGEND FILER BURLEY* ARIMO•
GRACE GEORGETOWN
WILLIAMS PIPELINE MALTA
INTERMOUNTAIN GAS CO.SERVICE LATERALS MONTPELIER
• TOWNS SERVED BY INTERMOUNTAIN GAS CO.
O INTERMOUNTAIN GAS CO.OFFICES
14
SeeNf:25 MILES 1
15

REGIONAL PIPELINES
Imo a
►Layers/Legend
1?ctorl, ►Basemaps
.e
- - ►Find address
S sill a Print
_ o
,Ply is — Montan
Helena
n_
\ dvl ac
Ilings i
p Q
O
rS tern
[k
Oregon A
Boise I d.9»F all s
ed ord
_ Choy
`.► t 15
200k� (� n A n
100mi tlyh y
rCy t
16

INTERMOUNTAIN GAS COMPANY
INTEGRATED RESOURCE PLAN
ECONOMIC FORECAST
RYAN DENTON
17

INTERMOUNTAIN GAS COMPANY
INTEGRATED RESOURCE PLAN
WOODS & POOLE ECONOMICS, INC. Regional Projections
The methods used by Woods & Poole to generate the county projections proceed in four
stages:
• First, forecasts to 2050 of total United States personal income, earnings by industry,
employment by industry, population, household size, inflation, and other variables are
made.
• Second, the country is divided into 179 Economic Areas (EAs) as defined by the U.S.
Department of Commerce, Bureau of Economic Analysis (BEA). The EAs are aggregates of
contiguous counties that attempt to measure cohesive economic regions in the United States.
• The third stage is to project population by age, sex, and race for each EA on the basis of
projected net migration rates. For stages two and three, the U.S. projection is the control total
for the EA projections.
• The fourth stage replicates stages two and three except that it is performed at the county
level, using the EAs as the control total for the county projections.
18

INTERMOUNTAIN GAS COMPANY
INTEGRATED RESOURCE PLAN
Idaho Economic Forecast
For the State of Idaho and the Counties in Idaho
Future household growth, which is the key driver for future residential
customer growth, is modeled as a function of total population (less those
individuals in group quarters), and general economic conditions in the state.
In brief: good or improving economic conditions will speed up the rate of
household growth, however worsening or declining economic conditions will
slow the rate of household formation and the rate of household growth.
19

INTERMOUNTAIN GAS COMPANY
INTEGRATED RESOURCE PLAN
Idaho Economic Forecast Idaho Seasonally Adjusted Nonfarm Employment MoM Change()an 2019-Dec 2021)-BLS
6.OeM
COVID-19 Impact:
teow
The height of COVIDs impact on the economy occurred R R " R "
A i~ P^�r� g, 3 3`9�Y°9 d'�9 xa�o� � i 8o s r``��q° i xa o
z.owa
primarily between March and May 2020. In April 2020 -
Idaho saw a seasonally adjusted nonfarm employment fr
decline 10.3% MoM (a loss of 79,300 in nonfarm £ book
employment from the previous month). �-
le—
rz-
Although there is a sharp recovery in the following Idaho Seasonally Adjusted Nonfarm Employment()an 2019-Dec2021)-BLS
month, with reversion to pre-pandemic levels, this ap°
recovery in MoM changes takes time to work itself °
through the levels of employment. Here we see
residual effects in the following months/years, but we `„°°
do see reversion back to the pre-pandemic trend rather
quickly.
a sego
19
ezo°
R R R R R R R R .R R R .R 11 xa xa IV A?r A r' F, r' s .�` Y~ d, w o . 4 i P r' Is �` �9 d, o „• r�• P" r'�• g• s• �`" �P�' cf, xa od•
20

INTERMOUNTAIN GAS COMPANY
INTEGRATED RESOURCE PLAN
Idaho Economic Forecast Idaho Population YoY Change(2010-2024)-W&P&BLS
3.
Population: 3.00%
2b
The growth in population has been a driving force in
economic growth prior to the pandemic and
y 159w
continues today, though it has slowed down a bit
since 2021 . Population growth has brought new 1
jobs to the state and help boost the economy. °
Total population in Idaho has increased at a robust °°°%
AIO All Ala A13 A11 Al5 Alb AIJ A10 A19 AA A21 AZ2 A23 2a21
pace since 2013. From 2019 to 2021 Idaho saw the Idaho Total Population(2010-2024)-W&P&BLS
highest YoY percentage change in population in the
nation, with the average YoY change being about 2�
......................................
2.37%. This is an increase in the population of
around 97,470 over these three years.
]590
This rapid increase in population was driven mainly
by domestic migration from more expensive and
densely populated states like Oregon, Washington, 20
and California.
°
A19 A11 Ala A13 MA A35 A19 AS] AI9 A19 20A A21 2921 2023 A24
21

INTERMOUNTAIN GAS COMPANY
INTEGRATED RESOURCE PLAN
Idaho Economic Forecast Idaho Sea sonallyAdjusted Nonfarm Employment YoY Change(Jan 2015-April2025)-BLS
me
Employment:
The top graph shows the total nonfarm
................... . ............................. .......... ............................
employment YoY changes for each month
from January 2015 to April 2025. The bottom
"ot'"�'"+'d'�''d',� ^a'a'^of'�.•�'+'A'B,s^ d'0.•�'"`'"at;�� a'.,� aa`.>`r'`r':.r,yc aof'�a rd r,�,r,yc ra�,rd�rst 3 yo rap'F rS r,�'.a'�y'?af`�.rd
graph shows total nonfarm employment over
s°
that same period.
Idaho Seasonally Adjusted Total Nonfarm Employees(Jan 2015-April 2025)-BLS
There appears to be a slowing down largely 9 .0
due to a normalization of the labor market e'S°
Wo
after an abnormally fast post-pandemic
825,0
growing period. Other factors include ��
slowing wage growth, slowing population
A6U
growth, falling working-age to retirees ratio, E'�°
n5.°
and broader economic conditions. But still
7W.a
strong growth. 675.0 21
660.0
6]6.a
22

INTERMOUNTAIN GAS COMPANY
Idaho Economic Forecast INTEGRATED RESOURCE PLAN
Idaho Seasonally Adjusted Education&Health Services Employment YoY Change(Jan 2015-Apri12025)-BLS
Employment:
The top graph shows the education and health
.................................. ...........
services employment YoY changes for each
month from January 2015 to April 2025. In d °
2025 thus far we've seen a YoY change of °:F°¢, �,,a,, , •�,s•o,• a,, e, �,,,• •�,•,•,•�, 9�,9�� �,:2. o a��ap�aa �,3� a����M1 ry�n, f��
r y+ r°`r .�a r•r y e r•rye .a`r'r �''a r'' • a r°`r° a r r •3'e •r°r �'��°e r W �'e a r
x.o
3.9% in January, 3.2% in February, 3.4% in ,°
March, and 1 .8% in April (though April is -
subject to revision). Idaho Seasonally Adjusted Education&Health Services Employees(Jan 2015-Apri12025)-BLS
1<5
IJO
35
The bottom shows this same sector but the
130
actual levels of employment over that same 9125
period. `'p
..............
v 135
E 11e
°105
1.
........ •" 22
96
90
ti� s�.� a,� e e o.,a a,� � � , y � � a o e.,e e a e a.�,.,a �iP•t°ti°_N n°��tin ti A A 4 6 A+6 �i T'A ti',(�i ti rP ti �`ii'
,>°�e,S to,>,.pe pais��F,e j,5�J,,lc?a�`•°1,m rid 3,�e�a��o•2,•e��1,d�3qv was d�..i1•s 3,,�e?a��•2a 1,•6\3,�o?d�o le�,m>3,fo?d sec rm ri 3,,�c?S"�o ro 1,e S,,�o?d"�•�o red y,�c?ap•`•
23

INTERMOUNTAIN GAS COMPANY
INTEGRATED RESOURCE PLAN
Idaho Economic Forecast Idaho Seasonally Adjusted Manufacturing Employment YoY Change(Jan 2025-Apri12025)-BLS
Employment: so
The top graph shows the YoY percent change
in manufacturing employment from January - -
...................
zo _ .
...........................
2015 to April 2025. In 2025 thus far we've seen
eo
a YoY change of 2.8% in January, 2.9% in
February, 3.2% in March, and 3.6% in April 2°
(again, April is subject to revision).
Idaho Seasonally Adjusted Man u(acturing Employees(lan 2015-Apri12025)-BLS
The bottom shows this same sector but the
actual levels of employment over that same
period.
................
.............
Overall Idaho is showing a lot of population and
E
'ems
employment growth strength.
23
,_`r'°`r �°r ,a`r°r �°+ •'`r'r y°r ,a`r'°`r° �r r'r �°a m r'r` �t`�e`r°r �a ,e r°r �°r'A,'�r°r°�3�°+a,'`ra r'��9�z�,°`r'°`^
24

INTERMOUNTAIN GAS COMPANY
The Economic Forecast INTEGRATED RESOURCE PLAN
Idaho Projected YoY Percent Change in Total Employment(2025-2030)-W&P
In the 2025 — 2030 Forecast Period Idaho's
Economy is currently expected to experience:
An average YoY population growth of 1 .05%, with _
the State's population reaching around 2,114,477 in
2030.
2.2.
An average YoY increase in total employment of „
about 15,642, adding around 93,870 jobs. 2025 2- 2027 2- 2- 2030
Idaho Projected YoY Increase in Totat Employment(2025-2030)-W&P
Ada and Canyon counties are projected to attain a 58
total combined population of about 868,976 in 2030. 15.7
iss
15] 2°25 2028 2021 2028 2020 2030
25

INTERMOUNTAIN GAS COMPANY
The Economic Forecast INTEGRATED RESOURCE PLAN
Nonfarm employment in Idaho is expected to increase on
average 1 .27% YoY over the 2025 to 2030 forecast period,
which is around a 93,179 total increase.
Some specific sector projections: •• ' ' ' '
Farm �
Farm employment is projected to increase on average 0.28% GMEW
YoY over the forecast period, which is an increase of around Manufacturing 0.34% 1,676
691 . Construction 882
Manufacturing employment is projected to increase on average
0.34% YoY over the forecast period, which is an increase of
around 1 ,676.
Construction employment is projected to increase on average
0.16% YoY over the forecast period, which is an increase of
around 882.
26

INTERMOUNTAIN GAS COMPANY
The Economic Forecast INTEGRATED RESOURCE PLAN
Combined, the transportation & warehousing, wholesale
trade, retail trade, and utilities sectors are expected to see
an average YoY percent growth of 0.66% over the 2025 to , ,
2030 forecast period, an increase of around 8,766 in
employment. Transportation 1.01% 3,230
Wholesale Trade 0.46% 1,104
Combined, the finance & insurance and real estate & rental Retail Trade 0.53% 3,964
& lease sectors are expected to see an average YbY
percent growth of 1 .52%, an increase of around 12,873 in utilities 2.08% 468
employment. Finance &
0.93% 3,338
Insurance
You can see the individual projections in the table. Real Estate & 1.95% 9,535
Rental & Lease
27

INTERMOUNTAIN GAS COMPANY
The Economic Forecast INTEGRATED RESOURCE PLAN
The service industries in Idaho are projected to see the
most growth.
AvgYoY Totalincrease
Combined, the professional & technical services,
education, health care & social assistance, state & local Professional & 1.67% 8,416
government, accommodation & food services, and other Technical Services
services employment are expected to see an average YoY Education 2 88% 5,154
percent growth of 1 .85%, an increase of around 57,298 Services
over the 2025 to 2030 forecast period. Health Care & 2.65% 21,776
Social Assistance
o State & Local
This growth in the services industries represents 61 .49 /o of 1.02% 7,252
the total increase in nonfarm employees over this period. Government
Accommodation
& Food Services 1.81% 9,664
You can see the individual projections in the table. other Services
(Excluding Public 1.41% 5,036
Admin)
28

INTERMOUNTAIN GAS COMPANY
INTEGRATED RESOURCE PLAN
The Economic Forecast,
QUESTIONS ?
28
29

RESIDENTIAL & COMMERCIAL
CUSTOMER GROWTH
RYAN DENTON
RESOURCE PLANNING ECONOMIST I
30

INTERMOUNTAIN GAS COMPANY
OPERATIONS DISTRICTS
yyashingmn
Fremont
AHO FALLS
yet0e ce,n DISTRICT
.•
Madism
• n •
• • •' • • S•
' OISE -
' ba DISTRICT •. Bonneville
Blaha •
arnare
•
TWIN FALL wham
NAMPA • DISTRIC POCATELL
DISTRICT • Gooding• lnmin • DI RICT
• drib-
• •
• Mn daka •
3— Ptwer Bar•ock •
• • • • • ' •
Owyhee • •• • •
Twin Falls •
Casa. • Bear lake
A INTERMOUNTAIN" 30
"GAS COMPANY
31

Intermountain Gas Co.
w.hmgm^
Areas of Interest(A01)
Fremom A01
N.State Street
ette �m •• •rx'C.)W
• •
T H
• �eRersan •
Central A
• • • Idaho Falls = •
• L ateral
any • Bonne ilk
RATE
Coun ^"� •
Blaine •
emare —� •
Sun Valle a,.ham
• Lateral
• Gooding• • Lincoln • •
• All Other
•
• Caribou
• Minidoka •
All Other Demme mower UVock •
•
Owyhee • • • •• • • •
•
Twin Falh •
asva • Bear lake
All Other
32

INTERMOUNTAIN GAS COMPANY
INTEGRATED RESOURCE PLAN
Base Case, High Growth, Low Growth
The Base Case Economic Forecast assumes a normal amount of economic
fluctuation and normal business cycle. It is the "best estimate" of future
economic activity in Idaho and its counties.
The Low Growth Scenario assumes a period of slower economic growth, with
fewer employment opportunities, leading to a slower rate of population growth
in the state and a slower rate of household growth.
The High Growth Scenario assumes a more rapidly growing economy, such as
what happened in the 1990s and what we have seen more recently.
33

CUSTOMER COUNT: FORECAST INPUTS
We use total number of households and total employment data provided by Woods & Poole.
Households are defined as occupied housing units. A housing unit is a house, an apartment, a group of
rooms, or a single room occupied as separate living quarters.
The employment data include wage and salary workers, self-employed workers, private household
employees, and miscellaneous workers. Historical employment data, 1969-2022, are from the U.S.
Department of Commerce, Bureau of Economic Analysis.
34

CUSTOMER COUNT: MODEL SELECTION
AICc: Corrected Akaike Information Criterion
Model Fit
SMAPE: Symmetric Mean Absolute Percentage Error
Model Accuracy
aEa ReaiCentiai 26 M—Customer Count Forecast ad.commercial 24 1,1o1h Customer Count Far.-V
£12900
Co
L � Ma<a.mhrui r�rramee FaCr�nCa
1-0
� U
35

CUSTOMER COUNT: FORECASTING COMPONENTS
■ Customers = R0 + (3 i H H + R2Emp +Trend() + Monthly Data with Increasing Trend and Seasonal Components
Fourier(period = "year", K) +ARIMA(p,d,q)(PDQ) — K=1 Harmonic
to K=2 Harmonics
— K=3 Harmonics
■ Where:
■ HH: Number of Households; E
■ Emp:Employment, 6
■ Trend():Deterministic trend component,
4
■ Fourier(period ="year", K):Captures seasonality using K
harmonics, Z
■ ARIMA(p,d,q)(PDQ):p = nonseasonal autoregressive
terms,d = nonseasonal differencing,q = nonseasonal 0
moving average terms.P = seasonal autoregressive terms, o s to u 20 25 36 35
D = seasonal differencing,Q = seasonal moving average Time(months)
terms.
35
36

. COUNTY CUSTOMER FORECAST
Ada County Residential Customer Count Forecast
1a,so0 Ada County Commercial Customer Count Forecast
210.000
205.0o0 14.250
200,000 10.000
195,000 13.-
19 OD
La 13.500
SB5.000 E
'^ 13.250
U
U 160,000
° 13.000
~1)5,000
12,)50
i)0,000
2.500
165.000
12.250
160,000
155,000 12.000
—N6loiicel —Base —Low —H66 —X¢taictl —Bae slaw —XgX
Average YoY growth: 1.7% Average YoY growth: 1.3
Total growth: 10.3%, 18,393 customers Total growth:7.8%, 1,026 customers 36
37

BEAR LAKE COUNTY CUSTOMER FORECAST
Bear Lake County Residential Customer Count Forecast Bear Lake County Commercial Customer Count Forecast
1.360 48
1.360 2e6
z44
1,340 242
240
330
238
1,320 236
1. 234
310
232
1,300 230
C
E 1.2W E 228
0 226
� 1.280 �2I4
U 222
1,270
0 220
~1.260 ~218
1,2 216
50
214
1,240 2U
210
1,220,230 1
208
206
20
1,210
202
1,200
ryo''��,yAr,yo'1��'{Y6ry0�,('1Ar,y�,�'�'Pti�,{'1'�•[M1.�ph���n;J��ryM1h.�,ly�ryo�,`'��,[�e��'PM1M1�,L��,1;M1M1�'L�M10�,�'��.L�O M1OOV��,yo�p'E�.���'E��'N��`'C' ^P'� ti��'lS.����'Ds�M1�''G>OA,A'{�'C>�A�'t h�ry�o M1�ti p'L M1�'L.�1'L M1"hy�'E''G'O.�'{°O�'C'�M11�h ory�oti'L�M11�'l�O1ry0�ti M1 O'Ls��'Y'�'Ci'P,�+��J�� �o 'E,�o�9'��
�P M1ro°r�M1°M1 ro°�'E-E� �M1°M1M1 � M1°M1° '?'M1°M1 v �M1°�M1 M1°-Ary�� �M1ro°� t? ro°•fti�M1M1 M1 �
—nsw��a —ease —row —Hen —es1«��a —base —mw —nen
AverageYoY growth:0.7% AverageYoY growth:0.7%
Total growth:4.3%,54 customers Total growth:4.3%,9 customers 37
38

FORECASTING GROWTH-AREAS OF INTEREST (AOI)
Intermountain Gas Co.
wazhingmn
Areas of Interest(AOI)
Fremo�n
N.State Street
.yens Gem
• ,errerson •
Central A a
• •anion • Idaho Falls t •
�
• ateraI
any .
Coun Ada • Bo"^evllk
Blaine •
Elmore
Sun Valley B:gham•
• Lateral
• Gooding• Lincoln •
• • • All Other
•
� Caribou
• •
• Mnidoka •
All Other S.Wck •
• • • • • • •
orryhee • .• •
•
Twin Falk •
Casva • Bear lake
All Other
38
39

CANYON COUNTY CUSTOMER FORECAST
Canyon County Residential Customer Count Forecast
Canyon County Commercial Customer Count Forecast
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4zm
'Q 9 R ro R 9 ro 9 ro 't'-9 ro ro 9 k 't'9�ro 9 k 't'ro ro R ro-P ro 9 R'Q 9 R 't'R 9 9-g ro ro R R ro ro ro ro 9 k 9 ro R 'Q ro ro ro�roproa 9ag'dp"d9rohroRro 9 srorororo`9�R�ro R�ro�9%g%ro R�%roRrororororo ro�rorororo�,g�,PT ro�R ro�rorororororo ro R%Pro'f'%ProRro ro�@%Broro�R 4�ro R9ro9
�HntoncY �9ase lox �Hg� M ton Y l Average YoY growth:3.1% Average YoY growth:2.4%
Total growth: 19%, 12,201 customers Total growth: 14.5%,696 customers 39
40

SUN VALLEY LATERAL CUSTOMER FORECAST
Sun Valley Lateral Residential Customer Count Forecast Sun Valley Lateral Commercial Customer Count Forecast
a,mo
L5e0
L3.Ao L5A
LSW
L.WO
LSSD
2.W0
L5m
2,Wo L5W
Om
L z.mo E Ey L53o
2.A0
U U
F U.W0 c Ld90
~ LdW
mo
LdA
Wo
LdW
S1.m0 Ld'A
Lam
11.Ao
Ld30
mwo LaA
'BpPakp`�[e-mail]'PARAP�P�k��P�P�R�R 9�`�P�h��R��k�'g Rk PkR'�P4`PA`p PAP�P'�R P�'g P�9�9�R 4'9'p P9h10P'9�9E9'p PAPA P6R PN'p 9aRaPA�kA'Q 9�kAR�R kry.9,B''42''P9M�h'.6'g kN9M9k�Bk,p 9k9k9'�9APA"{,P�9�9��k�'P 9�B�9�PSk�'B 9�P�B�R h9,Q�9�9
—Heloa<x —exie —lo. _Hen _s+ewa<x —ease —toe —Hen
Average YoY growth: 1.5% Average YoY growth:0.2%
Total growth:8.8%, 1,050 customers Total growth: 1.1%, 16 customers 40
41

IDAHO FALLS LATERAL CUSTOMER FORECAST
Idaho Falls Lateral Residential Customer Count Forecast Idaho Falls Lateral Commercial Customer Count Forecast
�.mo firm
69.W0 6.,W
®.mo 4BW
6.W0 ].6m
66 mo
],am
65.m0 ].6W
6d,Wo ].—
o mo ,n],dm
L
E 62.m0 E ],3m
U U A ].Im
eB mB —
`b.m0 r ].Bm
fiBW
`R.WO
46W
s].ma
4]m
56.WB
fi6m
`3.m0
fi6m
SG.mO 4dW
S m0 43W
Si.WO 4]W
�Hemncal Base Lox �Hgli �Hmm�cd. �fiase �Lwv �Ng6
Average YoY growth:2.2% Average YoY growth: 1.6%
Total growth: 13%,7,527 customers Total growth:9.7%,684 customers 41
42

NORTH OF STATE STREET CUSTOMER FORECAST
North of State Street Residential Customer Count Forecast North of State Street Commercial Customer Count Forecast
®.Wo s.oW
6)Wa s.oW
66.W0 49W
65.W0 49W
64 m0
4:
6).WO 46W
62.W0 4�50
L
E 61.Wo
a6W
U U
9 59.Wo 9 46W
~ 56.W0 ~45W
5.wo 45W
s6.Wo aaW
..Wo aaW
..Wo 4350
`3.Wo a3W
S.wo 42w
�HewntalBase �Lwv �Hgl
-HewnW Bare �lwv �Hgn
AverageYoY growth: 1.7% AverageYoY growth: 1.4%
Total growth: 10.3%,6,032 customers Total growth:8%, 364 customers 42
43

CENTRALADA
CUSTOMER FORECAST
Central Ada Residential Customer Count Forecast Central Ada Commercial Customer Count Forecast
se.mo 4am
61.mo
43m
43W
m.Wo
42W
Ed,mO
42m
63.m0
63.Wo 4,—
E61.m0 E 41m
W.mo �aoW
U U
�W.mO 9 4om
39m
S],mo
39m
36m
W o
SI,Wo 36m
S.mO 3JW
52,mo
3)m
-Hemncal -base �Loe -6h -Hemnvl &.:. lox -Heb
Average YoY growth: 1.7% Average YoY growth: 1.4%
Total growth: 10.3%,6,104 customers Total growth:8%,316 customers 43
44

TOTAL SYSTEM CUSTOMER •
Total Residential Customers Forecast Total Commercial Customers Forecast
4W.WO
........ 42,DDD
41.000
4..-
41.,.. 39.000
sa.-
2
-2 390.000 37.000
AM
Average YoY growth: 1.9% Average YoY growth: 1.4%
44
Total growth: 11.2%,44,474 customers Total growth:8%,2,985 customers
45

QUESTIONS ?

10 MINUTE BREAK

HEATING DEGREE DAYS & DESIGN WEATHER
BRIAN ROBERSTON
MANAGER, SUPPLY RESOURCE PLANNING
48

Weather is a Key Residential & Commercial Demand Driver
Heating Degree Days are Used to Capture Weather Effects
Two Primary Weather Scenarios are Used in the IRP:
Normal HDD
Design HDD
49

HEATING DEGREE DAY (HDD)
What is a Heating Degree Day?
Industry-Wide Standard Measuring Degrees Below a Set Base Temperature
Base of 65 Degrees is Most Common
March 2nd, 2023 - Boise Example:
Daily High: 39 Degrees OF
Daily Low: 23 Degrees OF
Mean: 31 Degrees OF
65 Degrees — 31 Degrees = 34 HDD
50

NORMAL HEATING DEGREE DAYS
Benchmark for the IRP
Used for Routine Planning and Represent the Typical or "Normal"
Weather Expected on a Given Day
30-Year Rolling Average of Daily Mean Temperatures
Normal for the IRP is the 30-Years Ended December 2024
51

NORMAL HEATING DEGREE DAYS
Normal HDD
1200
o 1000
v
v
v Bw
0
600
400
0
z
3 200
0
H
0
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aui Sep
51
52

DESIGN DEGREE DAYS
Design Degree Days Model the Coldest Temperatures that Could
Feasibly Occur on Intermountain's System
Created by Modeling Design Peak Day, then Modeling the
Surrounding Week, Month, and Year
53

DESIGN DAY
Design Peak Day is the Absolute Coldest Day Planned for in the Design Year
Engaged Idaho State Climatologist, Dr. Russell Qualls, to Conduct a Peak Day
Study
Study Produced a Range of Peak Days forVarious Probability Assumptions
50-Year Peak-Day Event was Selected (78 HDD)
Peak Day is Modeled to Occur on Jan 15th of the Design Year
54

P
EAK 5-DAY DESIGN
The Days Surrounding the Peak Day are Modeled After the Coldest
Recorded Consecutive 5-Days in a 50 Year Period.
Peak Day is Assumed to be the Second Day in the 5-Day Period.
55

Five Day Weather Forecast
Day 1 Peak Day Day 3 Day 4 Day 5
to At
®40,� PEAK 5- DAY
DESIGN
Snow Snow Snow Snow Sunny
-11 ° F -130 F -120 F -90 F -60 F
December 21 st, 50-Year Peak Day December 23rd, December 24th, December 25th,
1990 Actual Event 1990 Actual 1990 Actual 1990 Actual

PEAK MONTH
DESIGN
Peak Month . .
90
80
70
The Days Surrounding the Peal< .,
5-Day Period are Modeled
After the Coldest Calendar
Month in the last 50YearsS '
30
The Current Peal< Month is '
December 198510
This Month Forms the Basis
for January Design Weather Da

DESIGNING OFTHEYEAR
The Rest of theYear is Modeled After the Coldest Heating Year in a 50Year Record
Oct 1984 — Sep 1985 Continues to be the Coldest
This Period Also Included the Coldest Critical Three Month Heating Period (Dec-
Feb)
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep
58

DEGREE DAY GRAPH
1800
Iwo
1400
1200
1000
800
/ %b
600
400
200
0
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep
•••••• Actual Heating Year 1985 — — Weighted Normal(30 Year Roiling) Design Year 58
59

♦ • DEGREE DAYS
Intermountain's service area is climatologically diverse
Idaho Falls or Sun Valley vs. Boise
Intermountain has developed unique Degree Days for each AOI
Methods used to calculate AOI Degree Days mirror the Total Company
approach
60

A• DEGREE DAYS
NATURAL GAS SYSTEM
INTERMOUNTAIN GAS COMPANY
Weather Stations West
to East: WEIaEP .,.°°•r °°-°
• KBOI !RATE -
FRum
� MOUTN Mu v v+ . .u.• IgNY
• KEU L PAR.
ME- •pAR CITY
ME
PARaaA, URO
• KTW F V;eR : . an .E,CHU NEr LER1aY
NCMECALE% 8, p�M BgSE ILEY RY
NAMPA A
• KSUN KUNA. E EwE IDAHO FALME
LS •
•AWOM
HEUSY
• KPI H �.. FlRTNtraSaT
agRELANC BAfALT
anwGr"m RNE
• KI DA
•FONT NALL
600:M0 MgLNpiE ABEROEEN- BBUCK
• KRXE "EA" Nam° POCATELLO
I EIOELL - INP.OM
/� AaERICaN FALLir - � BAN:RCFT
ME \
U60laID RUPE�T i-"�� aCCANMON• iOOA iPRIN'iL
YULE FALLS PAVL• "jam-" UVA HOT.RUN =
F>.M EN Bib=.E)'Blgy—'R.FT RIVER APoYO. GRACE•
— '.�•...... �..... K�ERL�'-_t—_'pECLO °EOR°ETOVVI.
MURTAU H
'YONiPBIEq.
61

QUESTIONS ?

2025 IRP
LARGEVOLUME CUSTOMER FORECAST
JON WHITING & NICOLE GYLLENSKOG
MANAGERS, INDUSTRIAL SERVICES
63

WHAT 1 LARGEVOLUME CUSTOMER?
152 largest customers; approximately 49% of 2024 sales
Mix of "Industrial" and "Commercial" types
As a group exhibit fairly high load factor
Provide thousands of Idaho jobs; huge impact on economy
64

Annualized Large Volume Therm Sales
400
350
300
E
2 50
t
0 200
0
C
0_ 150
100
50
0
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
64
65

Intermountain Gas Company - Annual Therm Sales
800 100%
700 90%
N 80%
600
aV 70%
H 500 60%
O 400 50%
Ln
0 300 40%
200 30%
20%
100
10%
0 0%
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
Total Company Large Volume —LV % of Total 65
66

REQUIREMENTS OF A LARGEVOLUME CUSTOMER
Minimum 200,000 Therms per contract-year requirement
Must elect I of 3 tariffs:
LV- I bundled sales
T 3 interruptible transportation or T 4 firm transportation
Minimum one-year contract; the contract sets the term and Maximum
Daily Firm Quantity (MDFQ) for firm peak day use
Contracts are site specific; can combine meters on contiguous property
67

CLASSIFICATION OF CURRENT 152 LV CUSTOMERS
Percent of Total
By Rate Class: # of % of Therms
❖ LV I Sales — 37 24% 4%
❖T3 Interruptible Transport — 9 6% 9%
❖T 4 Firm Transport — 106 70% 87%
❖Total — 152 100% 100%
68

SEGMENTATION OF 152 LARGEVOLUME CUSTOMERS
■ By Market "Segment" # % Therms%
❖ Potato Processors — 18 12% 28%
❖ Other Food Processors — 17 1 1 % 32%
❖ Meat & Dairy — 24 16% 14%
❖ Ag & Feed — 8 5% 1
❖ Chemical/Fertilizer — 3 2% 8%
❖ Manufacturing — 33 22% 6%
❖ Institutional — 33 22% 6%
❖ Other — 16 1 1 % 5% 68
❖ Total — 152 100% 100%
69

LOCATION OF 152 LARGEVOLUME •
ByAO1: # % Therms%
I FL — 27 18% 17%
SVL — 4 3% 1 %
Central Ada — 2 1 % I
State Street — 4 3% 1
Canyon County — 20 13% 15%
❖All Other — 95 62% 65%
❖Total — 152 100% 100%
70

OVERVIEW OF FORECAST •
Most not as weather sensitive as the Core Market
Small population (not as many customers)
Not as homogenous as Core (size, weather sensitivity)
Don't use statistics/regression techniques
Use an "adjusted" historical usage approach
Forecast both Therm use and CD (MDFQ/MDQ)
71

APPLICATION OF FORECAST TECHNIQUE
Adjusted historical data with customer information and other
data (e.g. EDO's) to develop three forecasts
Base Case
High Growth
Low Growth
Assumed growth by specific customers
Used recent trends to validate results
72

SCENARIOBASE CASE ASSUMPTIONS
Starts with historical actuals
Adjust for customer information and trends
Natural gas prices competitive with other energy sources
Economy dealing with inflation and supply chain issues
Includes 5 new customers
Mix of segments; AI I T 4. 3 are "All Other" and 2 are in Canyon.
Compounded annual growth rate of 1 .9%
73

IRP Large Volume Base Case Forecast by Segment (Therms)
120,000
100,000
E
80,000
a�
o 60,000 -
_N
0 40,000
20,000 —
0
I
Potato Other Food Dairy and Ag Chem/Fertlzr Manufact Institutional Other
■ 2025 ■ 2026 Li 2027 2028 ■ 2029 ■ 2030 73
74

GROWTHHIGH • ASSUMPTIONS
Starts with Base Case Forecast
Natural gas prices remain comparatively low
Economy comes out of the inflation with continued growth
Assumes 10 new customers totaling 7.2 million Therms by 2030
Additions mostly T 4 (9); 3 Meat & Dairy and 7 various segments;
most growth in All Other
Compounded annual growth rate of 2.2%
75

IRP Large Volume High Growth Forecast by Segment (Therms)
120,000
100,000
E 80,000
L
Q�
60,000
O
O
o 40,000 —
20,000 loll
0
Potato Other Food Dairy and Ag Chem/Fertlzr Manufact Institutional Other
0 2025 ■ 2026 0 2027 2028 ■ 2029 0 2030
75
76

LOW GROWTH SCENARIO ASSUMPTIONS
Starts with Base Case Forecast
Assume gas prices are less competitive
Economy slows; recession or inflation causes slowing in growth
Removed any customer having difficulty staying above the
200,OOOTherm annual minimum
Two new T-4 customers; I in Canyon, & I in the "Other,"
segment
Compounded annual growth rate of 1 . 1

IRP Large Volume Low Growth Forecast by Segment (Therms)
120,000
100,000
E 80,000
L
0 60,000 -
_N
O
0 40,000 -
20,000 -
0
Potato Other Food Dairy and Ag Chem/Fertlzr Manufact Institutional Other
■ 2025 ■ 2026 012027 2028 ■ 2029 ■ 2030
77
78

IRP Large Volume Annual Therms
450,000
400,000
350,000
E 300,000
v
t
0 250,000
o 200,000
0
150,000
100,000
50,000
0
2025 2026 2027 2028 2029 2030
■ Base Case ■High Growth ■Low Growth
78
79

IRP Total Large Volume Annual Therms
500,000
450,000
400,000
350,000
v
300,000
250,000
0
0
0 200,000
150,000
100,000
50,000
0
2025 2026 2027 2028 2029 2030
-Base Case -High Growth -Low Growth
79
80

OPTIMIZATION MODELING -
MDFQVSTHERM FORECAST
d Use MDFQ not therm forecast in optimization model
Contract includes Maximum Daily Firm Quantity (MDFQ)
Intermountain provides MDFQ 365 day/year; gas supply
MDFQ trends therm projections
Only firm customers in design peak; no interruptible
Includes new customer additions
Compounded annual growth rate of 1 .5%
81

Base Case MDFQ by Segment
600,000
500,000
400,000 —
IA
—
s
H
200,000 -
100,000 — — -
d` c�\ca Sao et` �o
Cr
0 2025 0 2026 ■ 2027 2028 0 2029 0 2030 81
82

QUESTIONS ?

LOAD DEMAND CURVES
Incorporates several inputs
Res & Com Customer Forecast, Normal and Design Weather, Use Per Customer, Demand Side Management, and
Large Volume Forecast.
LDC = (Customer Forecast * HDD * User Per Customer) — DSM + LV Forecast
Load Demand Curve Utilization
Identifies potential upstream pipeline and distribution system constraints
Resource Optimization
Storage Management
Remedies for any constraints will be identified later
Note: Load Demand Curves for upstream pipeline modeling will differ from distribution system modeling
84

Total Company
6,000.000
5.500,000
5.0 00.000
4,500,000
4.000,000
3.500.000
3.000.000
2.500.000
2.0 00.000
1,500,000
1,000.000
500.000
O`1O O�y O`1b p`1y O`1O O�6 Oo OHO O�6 O`1O O`1O O`A A O�� O`1� p`1A O�0 O�0 O�0 OHO p`10 O`ti0 O� OHO OHO O� O`19 O`1O O� OHO O� OHO
1\L 1\L \1\ry \1�ry ti�L y1 1\L 41\ry 41\� \1�ry 1�ry 1\L \ti�L \1\ry 1\L \�L \1\ry \ti�L 1�ry 1\L \1\� \�L ti�L 1\L \1\� \1�� 1\L
84
85

AREAS OF INTEREST
■ Idaho Falls Lateral
■ Sun Valley Lateral
■ Canyon County Lateral
■ North of State Street Lateral
■ Central Ada County
85
86

Idaho Falls Lateral
1.000,000
950.000
900.000
850,000
800.000
750,000
700.000
650,000
v
600.000
550.000
500,000
450.000
400.000
350,000
300,000
250,000
200,000
O1� Otiy Otis oL(0 otiSO oLco oL`O obro co oy4b otirb oLA OVA OtiA OtiA otiA otiA 0l0 Oti0 OL0 Oti0 oy0 O�0 O�' ob°j O� oL°' oti0� oy°' O� O� O� O�
��ti ���ry �ti�ti ��� ��� ���ry ti�ti N 1�ti ti�ry ��ti \ti�ti 0�N�ti
0ti 0 ,,o .,� � a �d 0", .,o ti� � e� 0
86
87

Sun Valley Lateral
250,000
225.000
200,000
175,000
150,000
E
d
125,000
100.000
75,000
50.000
25,000
r�tiory`O'tioti�tiory`O'o
t� 0\ tio� ti� o� ca
87
88

Canyon County Lateral
1.200.000
1,150,000
1,100,000
1,050.000
1,000.000
950.000
900,000
850,000
800.000
750,000
v
� 700,000
650,000
600,000
550.000
500.000
450.000
400,000
350.000
300,000
250,000
oti�' oti�' oti�' oti�' oti�' oti6 oti° oti6 oti�O oti° oti° 0A otiA otiA 0A otiA otiA 0�lb oti0 oti0 11b oti0 oti° off'' o off' oti° oti° oti° o�
��ti ��T \ti�T \��T 41 ati �ti I\T \4T \ITT ,�T 41ti \1�T 41 \-I�ti \gyp pc '15ti�ti ��ti ��ti \��ti \�\T �\'P ti�ti `1�ti ��' 1�' \��ti 1�T ti\ti \�\ti \N\T ti\T
88
89

North of State Street Lateral
875.000
825.000
775.000
725.000
675,000
625,000
575,000
525,000
E 475,000
d
L
425,000
375,000
325.000
275,000
225,000
175,000
125,000
75,000
25.000
ti\ryp�y \vpryy \ryp�y
t1
90

Central Ada County
875,000
825.000
775,000
725,000
675.000
625.000
575,000
525,000
E 475.000
d
425,000
375,000
325.000
275,000
225.000
175,000
125,000
75,000
25,000
oP' oti�' oti�' oti�' oti�' oti�O oti�O oti�O oti�O oti�O off° oti� otiA oti� otiA oti� oti� oryO otiO otiO otiO otiO otio off' off' off' off' oryo otio 05° 050 050 050
D�~\T 4�1\ry 0�4T O�41 �41 i)4 b�4T ro��\T 0�~\� O�~\ry �ti\� 1�1\� D�1\ry b�1\� O�~\T O�~\T �1\T t)1\T D�1\T �~\T O�4v 0�1\T �1\ry t)1\� b�~\� �1\� O�~\ry O�~\ry ��� l�~\� b�~\� O`~\~ 0��v
'4 ti ti ti ti ti ti 1 'ti 'ti
90
91

QUESTIONS ?

ADDITIONAL MEETINGS
Wednesday,August 13, 2025 via Wednesday, September 17, 2025 via
Microsoft Teams Microsoft Teams
Usage Per Customer Potential Capacity Enhancements
Energy Efficiency Resource Optimization
Supply Side Resources Planning Results
Distribution System Modeling
93

FEEDBACK SUBMISSIONS
[e-mail]
Please provide comments and feedback within 10 days
94

IGRAC #1
INTERMOUNTAINO
GAS COMPANY
A Subsidiary of MDU Resources Group,Inc.
RESOURCEINTEGRATED
INTERMOUNTAIN •URCE ADVISORY COMMITTEE
Date &time: 7/9/2025, 9:00 AM to 11:00 PM MT
Location: Microsoft Teams Meeting
Presenters: Brian Robertson, Ryan Denton, Jon Whiting
In attendance: Adam Bohrer, Bailey Steeves, Brian Robertson, Bruce Folsom, Chris Robbins,
Darcy Neigum, Eric Wood, Jason Talford, Jon Whiting, Kathleen Campbell,
Kristen Nieskens, Mark Sellers-Vaughn, Nicole Gyllenskog, Rebecca Wildman,
Ryan Denton, Sean Keithly, Seungjae Lee, Teresa McKnight, Vicki Stephens,
Zachary Sowards
Introduction
Brian Robertson, Supervisor of Resource Planning, opened the meeting by welcoming and thanking
stakeholders for participating in Intermountain's IRP Process. Brian then proceeded with introductions,
the agenda, a safety moment, and a reminder of the stakeholder engagement goals.
Presentation #1 —2023 IRP Acknowledgement and IRP Recommendations (Brian Robertson)
• Recommendations
o Company work with Staff to implement IRP reporting that includes system enhancement
information
o File that information within six months of a Commission order
o Establish the practice of authorizing the Company's DSM avoided costs as part of IRP
filings and authorize the DSM avoided costs associated with this filing
Comment: Jason Talford noted, for the third recommendation bullet point, that the Commissions
findings in the order didn't direct for that to happen.
Presentation #2—System Overview(Brian Robertson)
• Large Volume 47% Residential 34% Commercial 17%
• Areas of Interest
o Canyon County
o Central Ada County Lateral
o North of State Street Lateral
o Sun Valley Lateral
o Idaho Falls Lateral
Page 1 of 2
95

o All Other Customers
Presentation #3— Economic Forecast (Ryan Denton)
• Stated the Company is utilizing Woods& Poole data for economic forecasts
• April 2020 saw a 10.3% decline due to pandemic
• Idaho's population increased 2.37% Year-over-year from 2021 to 2023
• Nonfarm employment is slowing down after an abnormally fast post-pandemic growing period
• Overall, Idaho is showing a lot of population and employment growth strength
Presentation #4— Residential & Commercial Growth (Ryan Denton)
• Forecast inputs
o Woods and Poole population and employment
o Historical customer count
o Intermountain performs Base, Low, and High forecasts
• ARIMA model with Fourier term
Question: "Why is household and employment used as explanatory variables over
population and income?"
Answer: "Household and employment are direct impacts to residential and commercial
customer counts, respectively. Population and Income are more of an indirect
impact. For example, population could increase, however, if the number of
people per household is also increasing, we may not see a similar rate of
increase in customer counts."— Ryan Denton and Brian Robertson
Presentation #5— Heating Degree Days & Design Weather(Brian Robertson)
• Heating Degree Day based off 65 degrees
• 30-day rolling average of daily mean temperatures
• Design Degree Days model coldest temperature from Design Peak Day
• Peak Day modeled to occur Jan 15
Presentation#6— Large Volume Customer Forecast (Jon Whiting)
• 152 large volume customers make up 49% of sales
• Minimum of 200,000 therms per contract year to be LVC
• Start with historic trends and add customer trends
• Forecasts broken out by classifications, segmentations, and location
• Intermountain performs Base, Low, and High forecasts
Presentation#7— Load Demand Curves (Ryan Denton)
• Load Demand Curve = (Customer Forecast* HDD *Use Per Customer)—DSM + LV Forecast
• Preliminary Load Demand Curves for Total System and AOIs were provided
The Meeting was Adjourned—IGRAC #2 will be held on August 13, 2025 @ 9 AM MT
Page 2 of 2
96

I 41FERIvAlClLj 4mrAl
GAS COMPANY
A Subsidiary of MDU Resources Group, Inc.
INTEGRATED RESOU RCE PL AN
AUGUST 13, 2025
INTERMOUNTAIN GAS RESOURCE ADVISORY COMMITTEE (IGRAC)

•
m I
■ Introductions
■ Feedback Process
■ Agenda

FEEDBACK
MISSIONS
■
[e-mail]
Please provide comments and feedback within 10
days
IRPWebpage: https://www.intgas.com/rates-
services/rates-tariffs/integrated-resource-plan/
3
99

1 . 1
Welcome & Introductions — Brian Robertson (Manager, Supply Resource Planning)
Safety Moment — Brian Robertson (Manager, Supply Resource Planning)
Distribution System Modeling — Kathleen Campbell, Zachary Sowards (Senior Engineer)
Avoided Cost Methodology — Zachary Harris (Mgr Regulatory Affairs II)
Energy Efficiency — Kathy Wold (Manager, Energy Efficiency)
jiciency)
Supply Resources and Transportation & Storage Resources
— Eric Wood (Manager, Gas Sup ply)
Questions/Discussion
4
100

SAFETY
MOMENT
Places prone to sunburn PROTECTION FROM THE SUN & HEAT
po Strongly burns Medium burns Sligntly burns
• Wear a Hat and Sunglasses— Besides
skin damage the sun can damage your
eyes; wear sunglasses with Z00% UV
protection. ----
Some people think
• Water— Drinking water keeps your about sun protection
body hydrated in warm weather. only when they spend a
day at the lake, beach,
• Sunscreen — Use sunscreen with SPF or pool. Remember,
15 or higher. The higher the SPF, the sun exposure adds up
better protection. Put it on every inch day after day and every
of exposed skins. time you are in the sun. /
• Time of Day—The UV rays of the sun
are strongest between loam and
4pm.Try to limit sun exposure during
this time of day; even on cloudy and
cooler days.
• Shade—The simplest and an effective 5
' 1 ' means of staying out of the sun is
101
seeking shadows or shade.

Demand Supply & Delivery Resources
Economic Overview Transportation
Capacity & Storage
. Distribution System
Residential & Commercial LINatural Overview
Customer Growth Gas Supplies
Non-Traditional
Design
Residential & Resources
Weather Energy Efficiency:
Commercial Usage
Per Customer --------------------=--- Residential &
Commercial
Industrial Demand
Demand Supply & Deliverability
Load Demand Curves
Optimization Modeling
System
Enhancements
6
Demand
102

AREAS OF INTEREST (AOI)
NATURAL GAS SYSTEM
J INTERMOUNTAIN GAS COMPANY
r CANADIAN GAS
■ Distribution System Segments: WASH.
MONTANA
■ Canyon County WEISER OREGON
AREA- WYOMING
OF MAP
PAYETTE
TVIONY
■ Central Ada County Lateral NEW PLYMOUT CALIF. NEVADA UTAH PARKER ANITY
FRURLAND COLORADO
-EMME \ U S GAS •SUGA CITY
"North
" P%RM STAR PG 1 O SAN UAN BASIN -SA7TREXBLIT GLNG
■ North of State Street Lateral MIDDLETON �Q�P MENAN0
WI R ARDEN CITY UN VALLEY IEWISVILLE RIGBY
GREENLW,, �, • BOISE
r I��QP K CHUM/ELKHORN UCO`N
■ Sun Valley Lateral 1P�°�P� U 1 • ILEY IUAHO FALLS IONv
AMMON '9iF
T ELLEYUE SHELLEY
�,O��OP QP� FIRT BASALT
■ Idaho Falls Lateral MT.HOME CANYONy�a�yF� M FORT BLACKFOOT
OR ,y
O GOODIN ABERDEEN• HUBS y4�f�
■ All Other Customers wENDEL: S SHONE AMER/CgNFACL • PON O LLO�O,
P S %P
BRUNEAU• t�O�QSF,�pJGQPJ~JyOPq S • •SODA SPRINGS
INGIS
• McCAMMON
LEGEND BURL FILER BURLEY OEClO ARIMO•
GRACE GEORGETOWN
WILLIAMS PIPELINE MALTA I
INTERMOUNTAIN GAS CO.SERVICE LATERALS MONTPELIER
• TOWNS SERVED BY INTERMOUNTAIN GAS CO.
O INTERMOUNTAIN GAS CO.OFFICES
7
Scale:251WLE5 I I
103

DISTRIBUTION
SYSTEM PLANNING
KA A 0BELL, PE - SENIOR ENGINEER
ZACHARY SOWARDS - SENIOR ENGINEER
I DAH O
104
AUGUST 13TH, 2025

SYSTEM DYNAMICS:
Piping:
Diameter — '/2" to 16"
Material — Polyethylene and Steel
Operating Pressure — 60 psi to 850 psi
Idaho — approx. 7,471 miles of distribution &
284 miles of transmission
9
105

SYSTEM DYNAMIC'S CONT
Facilities:
Regulator stations — Over 600
Other equipment such as LNG, gas quality, odorizer and compressors
10
106

SYSTEM DESIGN

SYNERGI GAS MODELING
To evaluate our systems for growth and potential future deficits we use our gas modeling software,
Synergi Gas
Distributed and supported by DNV
Models incorporates:
Total customer loads
Existing pipe and system configurations
Hydraulic modeling software that allows us to predict flows and pressures on our system based on
gas demands predicted during a peak weather event.
Models are updated every three years and maintained between rebuilds
12
108

SYNERGI
MODEL
D EXAMPLE
+
. ® =:��• _.� � � �
\
-
�
13

MODEL BUILDING PROCESS
F Synergi models are completely rebuilt every three years and
maintained/updated between rebuilds
When models are rebuilt
We export current GIS data to build spatial model
We export 5 years of CC&B billing data to CMM to create an updated demands file
We validation and calibrate each district model to a recent low-pressure event using
existing data (ERXs/pressure charts/SCADA/metertek/LV usage)
We create a design day model based on the updated heating degree day determined by
gas supply (determined by trending historical weather events)
IGC models were rebuilt in early of 2025
14
110

DATA
1 1 GATHERING
CC&B (Customer Billing Data) PROD ote„ Cue . . 1. ,1 :?0
1-2013 P , 55,902.05
AA,
Meru
06.2014 s788 K
12.20.2013 ay Seq o I S-5.02.OS S-5,902.05 $0.00
12N2011 $5902.05 $5 9.3205 $5,902.05
.y Seqrnt 5-s,,17 SD S3.171.S6 to
11-05-2013 Be segnwt $5,1L56 Ss,171.506
Bi)Nd
I eredconsumPnoe01 _
i li1
2014 2014 2014 2014 2014 2014 :014 2014 VIA 2014 2014 2013 2013 2013 V:l '01) 2011 2013 :01I Mil 2013 201) 713 2012 2012
11C) 1.1 1101 0605 0741 06.I 0sos owl olas ...Or.. ua It. 1oa1 Ow) 0605 o1Gl 060) ou1 Owl 03-05oi.1 12-0) lics
Timoline Me corcecc
Novefte, - 2014 - J+�+►�►
)FeM34 AMM14 S-- OdM14 M1 nw=4 DM2M JMS feiM1S MerM16
re Met Reeds(01 I
wk(11) ® GEI ® ■ ■ ■ 1
F,<)d Act, ,<s(0)
Casey(0)
15
))) ►
Done 111 ✓Trusted sites(Protected Mode:Off y !100%

DATA
1 1 GATHERING
■ SCADA Data
t GPNG
_,� QIGC Boise Usage
. NOTE:The information on this website is for informational purposes only.It is not real-time data and is NOT to be used for ■ Real time and historical
Idaho Falls
operational purposes.
Nampa flow characteristics at
> Pocatello Data View Mode Time Period
Twin Falls ® 10=111 specific locations in the
4 CNGC
Cur day Cur day Prev day Prey day
+MDU Monitored Area mcf/d Dth/d mcf Dth mclF Dth system
ALSCO LV Run1 0.0 0.0 37.0 40.2 25.6 27.8
BandDFoods LV Run1 101.7 110.6 34.4 37.4 23.5 25.5
BoiseStateBoiler LV Run1 0.0 0.0 0.0 0.0 0.0 0.0
BoiseStateEng LV Run1 0.0 0.0 3A 3.7 8.8 9.6
BoiseStateUniv LV Total 0.0 0.0 No data No data 8.8 9.6
CentralPaving LV Run1 0.0 0.0 139.0 151.1 3.0 3.3
CSBeefPackers LV Run1 1452.9 1579.5 490.0 532.7 285.0 309.8
DarigoldBoise LV Run1 30.5 33.2 10.4 11.3 29.6 32.2
Darling LV Run1 258.3 280.7 87.1 94.7 10.7 11.6
16
DoubleJMilling LV Runt! 0.0 0.0 129.0 140.2 309.0 335.8
112

DATA
1 1 GATHERING
■ Peak Heating Degree Day (HDD) modeled
by IGC based on historical weather data
Town HDD Avg Daily Temperature (OF) Peak HDD = 65 —Average Daily Temp
Boise 75 -10
NATURAL GAS SYSTEM
INTERMOUNTAIN GAS COMPANY
Nampa 68 -3 CANADIAN GAS
WASH. IIONTAl111
Pocatello 82 -17 WEISER OREGON
WYOMG
OF N
MAP
TE
PAYET
KER ANTNONY
FRURLAND NEW PLYMOUT 3 CALIF- NEVAOA AN �
El rt(iADQ SUGAR Ix�V
I.I.S. R%BURGIdaho Falls $$ —23 PAR
O STAR SA1 UAx eSx
MIODL MENAN
WI ARDEN CITY UN VALLEY EWISVILLE RIGBY
G EN BOISE
,y K CNUM/ELNNORN UCON
IONA
Twin Falls 77 —12 T UN I • ELLEVUE BN LEY µEL E, • MIN q�
1 ✓✓✓ F
P L
RRT BASALT �
/7�� M.HOME PPZVP MFFORT IN D BLACKFOOT ,{y
Ketchum 82 —17 O� GOOgN ME ABERDEEN HmU BEI
WENDEL. Q `+ JkER/C1Nf III PO BOLL,
CONDA
BRUNEAU P P J"'vV P J S
• S,L1V•fP JPgP Qq •SODA SPRINGS
MDCAMMON
�CLD AIRING.LEGEND BUNL FILER• URLEY
O CE GEORGETOWN
MALTA
MERMOUMAIN WS CO.SERVICE LATERALS MONTPELIER
• 11WNS111EDBYERERMOUNTAINOAEC1.
INTERMOUNTAANDASCO.OFRCES
E..x n N11— 17
113

CUSTOMER
MANAGEMENT
1 MODULE (CMM)
Customer Management Madulefor SynerGEE Gas,CMM%tOD
File Etlh — Assignment Load Analysis Tools Help
O-®cmm2adm Name Base Col.... Hed Col.... Cool Col.... Description
�`®-DemaM Gra.ps ®Commmcial
Meter 3 4
.-®Mder Codes ®Indurtrial 5 6
.® Rou[a ®IMerrvptible 7 6
®M.dda ®L.rgi-.me 9 10 Brings CC&B customer
®Rat.CoJ.
®st—Codes ®Omer 15 16
-®Usage Read Codes ®Residential 1 2
- _--®Normal Read _ ®special 13 12 data into Synergi as
---®UNKNOWN = ®Sr mlodMi...11 12
p-®Weather Effector Types
3® C G-ones
demands file
'.--®CNG-ARUNGTON WA Attubde' C.mh- %I..a:
t..® NBAKFROR Potld Code Isequd to 99M6
CNG-BFLtBJGHAM WA
®CNG-BREMERTON WA Seleclon Gileiu
--a CNG-BURUNGTON MOUNT VERNON W POSTALMDE='99336'
:--®CNG-HEM S0N OR
-:--®CNG-HOQUTAM WA
-:--®CNG-KELSO LONGWEW WA
-
-®CNG-MOSESIAKEWA ANO OR OO 0 FN®CNG Demand file applies
- -ONTARIO OR
®CNG-RASCO WA Rawls(998I:
®CNG-RFND'ETON OR S.—Id ml a AcmuM N..b B.. Heal W."Z" FeHc'. load spatially in t h e
a 1873610151 MD45M 0568 0.109 CNG PASCO WA 0
9-0 Chat P.I.s Chad Dde 772g593R9 P105912 0.233 0.106 CNG PA9C0 WA Piolie..
CAM Load Forecast 1917g17277 P2211 St1 0000 O.L97 CNG�PASCO WA
-�C.tl.me MeterH N.ry 86N 5Fa2 GV877 0.232 1.116 CNG FWi. A Edil..
- Effectors by T'me 5713268823 GL6MI 0.." 0.106 CNG PASCO WA model.
Reps m 98695g885 GL6701 0000 0111 CNG PASCO WA
--.a S—Out vx CMM L.ad 6506B13E65 P221162 IA21 O.T99 CNG PASCO WA
D IN fFWqMWA
M.bredi re—t ov<laneas
Albb- V..
Access Numbe UptlaM [ Selected iazultc mly
CGS Hep
18
114

■
CALIBRATEDVS
PEAK
1 DEGREE
R DAY
LOAD VS TEMPERATURE
PEAK DD
I
0.9 de y = 0.0152x + 0. 1118
0.8 CALItSKATtu DD �I �I
_ 0.7 ♦♦ ♦ HEAT BASE
LL 0.6
U ♦♦
0.5
♦ • 4o DD = 0.72 MCFH
0.4
0.3 58 DD = 0.99 MCFH
0.2
0.1
0
0 10 20 30 40 50 60
DEGREE DAY
19
115

IDENTIFICATION OF SYSTEM
DEFICITS/CONSTRAINTS

SYNERGI MODELING CAPABILITIES:
Review Large Volume Customer requests
Model RNG
Supports design/sizing of pipe and pipeline components (regulator
stations, compressors)
Future planning
Model IRP predicted growth
Identify deficiencies
Determine system reliability
Optimize distribution enhancement options
Cold Weather Action Plans and Modeling Curtailments/Interruptible
Customers 21
117

WHAT
1 CAPACITY
DEFICIT?
A deficit is defined as a critical system that is at or limiting capacity.
Critical system examples include:
Pipeline bottlenecks
Minimum inlet pressure to a regulator station or HP system
Minimum inlet pressure to compressor (suction)
Component limiting capacity
zz
118

i
DISTRIBUTION
MEET IRP GROWTH PREDICTIONS
As part of the IRP process, we complete a comprehensive review of all of our
distribution system models every two years to ensure that we can maintain reliable
service to our customers during peak low temperature events.
With our capital budget cycle, we also complete system reviews on an annual basis.
If a deficit is predicted the system is evaluated and a reinforcement/enhancement is
proposed and selected based on alternative analysis considerations and placed into
the capital budget based on timing needs of the predicted deficit.
23
119

DISTRIBUTION
ENHANCEMENT/ REINFORCEMENT
OPTIONS TO ADDRESS DEFICITS

ENHANCEMENT
OPTIONS
Pipeline:
Replacements
Reinforcements
Loops & Back feeds
Pressure Increases
Uprates
Facility Upgrades
Additional Regulator Stations feeding the distribution system
New Strategically placed Gate Stations
Compressor Stations
25
121

DISTRIBUTION ENHANCEMENT EXAMPLE
Facilities Color By
Theoretical low- - Pressure (Primary Only) (psig)
4 ■ Not Applicable (7)
pressure scenario ■ < 10.00 (301)
❑ 10.00 - 15.00 (518)
■ 15.00 - 25.00 (548)
--� ■ 25.00 - 40.00 (627)
x ■ 40.00 - 60.00 (67)
■ > 60.00 (16)
26

DISTRIBUTION ENHANCEMENT OPTIONS
Facilities Color By
Pressure(Primary Only)(psig)
Low pressure scenario Not Applicable(7)
4 C 10.00 (301)
❑ 10.00- 15.00 (518)
❑ 15.00-25.00 (548)
25.00-40.00 (627)
T - r 40.00-60.00 (67)
>60.00 (16)
Compressor station
infeasible
Other Solutions?
r
CASCADE
NATURAL GAS 27
R,
C O R P O R A T 1 O N
A Subsidiary efMUUReeuroes Group,/M
In the Community to Serve®

DISTRIBUTION ENHANCEMENT OPTIONS
%
Reinforcement option # I
.11 A,8uN5TC-N
WA SW* WA-SION6jW 64
-!4
NO
17Z 28
124

fl•
DISTRIBUTION ENHANCEMENT OPTIONS
Facilities Color By
Reinforcement option #2 Pressure(Primary Only)(psig)
Not Applicable(8)
< 10.00 (0)
❑ 10.00- 15.00 (780)
15.00-25.00 (367)
* 25.00-40.00 (844)
• 40.00-60.00 (71)
>60.00 (16)
AL
29

ENHANCEMENTS
CONSIDERATIONS
■ Scope
■ Cost
■ Capacity Increase
■ Timing
■ System Benefits
■ Alternative Analysis
■ Feasibility
30
126

ENHANCEMENT REVIEWAND
SELECTION PROCESS TO CAPITAL
BUDGET

ENHANCEMENT SELECTION GUIDELINES:
Shortest segment of pipe that addresses deficiency
Segment of pipe with the most favorable construction conditions
Segment of pipe that minimizes environmental concerns and impacts to the
community
Segment of pipe that provides opportunity to add additional customers
Total construction cost including restoration
32
128

ENHANCEMENT SELECTION PROCESS:
District Info:
Design Day
IRP Growth Data -City Developments
Models
-New Housing Plats
Info & Data
System Limitation
Computer Model Pressure
Concerns
BENEFIT
FEASABILITY
ID Potential Projects and
Enhancement Types
(Individually)
`°" Project & Schedules
I
> Rank Projects Based
O
FEASABILfTY n Priority
co 33
Schedule Into Budget
129

ITERATIVE PROCESS OF IRP
20251RP 2027 2028 2029 2030
20271RP 2028 2029 2030 2032
2029 IRP
2030 2032 2033 2034
34
130

QUESTIONS ?

AVOIDED COST METHODOLOGY
ZACHARY HARRIS
MGR REGULATORY AFFAIRS II
132

■
A BRIEF HISTORY
INT G- 19-04, Order No. 34536 directed the Company to review its avoided cost calculations.
In early 2020, Intermountain invited interested members of the Energy Efficiency Stakeholder Committee (EESC)
to join an Avoided Cost Subcommittee.
Met three times between February and June 2020
The Subcommittee came to an understanding on the general Avoided Cost methodology
Avoided cost subcommittee met in March of 2022
Could not agree on distribution cost (still set at 0)
In Order No. 35663 Commission approves the Company's proposals to streamline avoided cost updates by
including them in IRP filings, discontinue their inclusion in DSM pruriency filings, and align program planning and
cost-effectiveness testing with the most recent IRP and applicable avoided costs.
37
133

AVOIDED COST OVERVIEW
"A Penny Saved is a Penny Earned ."
The Avoided Cost is used to put a dollar value to energy savings.
This allows utilities to spot opportunities where energy efficiency is more cost effective than a supply-side option.
38
134

NATURAL GAS SUPPLY CHAIN
Gas Field Processing Transmission Gateway Distribution
� � T v
r
e
Oil and gas wells Gas processing Pressure """"""
Gas wells to specification reduction and
Coal seams Odorisation regulation '
Compression Flow metering 1990kh...
Metering �0
Residential Commercial
Production Transmission Distribution
0
• • � � • • Distribution
Costs • Costs
39
135

• A
ACNominai CC + TC + VDC
ACNominal = Nominal Avoided Cost Per Therm
CC = Commodity Cost
TC = Transportation Cost
VDC =Variable Distribution Cost
40
136

COMMODITY COST CALCULATION
The price of a molecule of gas depends on the basin, the time of year, and even the day of the week.
Calculation starts with internal 30-year price forecasts for three primary basins.
Basins prices are weighted based on company Day Gas purchase data.
Normal Heating Degree Days (HDD65) are used to shape monthly prices.
41
137

TRANSPORTATION COST CALCULATION
Includes the cost of reserving additional capacity on the Northwest Pipeline.
Based on costs & volumes listed in latest tariffs for RS and GS- I customers.
Also contains variable costs associated with transporting gas to city gate.
42
138

DISTRIBUTION COST CALCULATION
Energy efficiency can lead to delaying or even avoiding costly pipeline capacity expansions.
Large expansions occur irregularly, making it difficult to quantify this type of saving.
Currently, the calculation contains a placeholder value of $0.00 for this cost component.
As part of this IRP Process, Intermountain will work with stakeholders to try to develop a distribution system
cost.
43
139

2025 IRP UPDATES
Levelized Avoided Cost by Year
Discounted 2024$
Updated Basin price forecast. �Year Updated Cost Previous Cost
Updated HDD Shaping to use 2024 Normal weather. 2025 $0.58 $1.05
2026 $0.67 $0.99
Added new year of Day Gas purchase data. 2027 $0.69 $0.93
2028 $0.70 $0.89
Updated transportation cost with latest PGA tariff. 2029 $0.70 $0.85
Inflation Rate updated from 3. 15% to 3.99 %. 2030 $0.69 $0.82
2031 $0.69 $0.80
2032 $0.69 $0.78
2033 $0.69 $0.77
2034 $0.69 $0.76
44
140

QUESTIONS ?

KATHY WOLD
MANAGER, ENERGY EFFICIENCY

Energy
irip- nr , -
Demand Side Management (DSM) refers to
resources acquired through the reduction of
natural gas consumption due to increases in
efficiency of energy use.
47
143

Energy
INTERMOUNTAIN"'GAS COMPANY 0 Efficiency
Rebate Minimum Efficiency Incentive Amount
Combination Boiler for Space and Water Heat 95% AFUE $800
Furnace 95%AFUE $350
Boiler 95% AFUE $800
Storage Water Heater .68 UEF $115
Tankless Water Heater Tier 1 .91 UEF $325
Tankless Water Heater Tier II .87 UEF $300
Smart Thermostat ENERGY STAR!. Certified $100
Use the ENERGY STAR Smart Thermostat Finder.
48
www.intgas.com/saveenergy
144

Energy
INTERMOUNTAIN"'GAS COMPANY 9 Efficiency
WHOLE HOME TIER I - $900 WHOLE HOME TIER II - $700
• HERS rated • HERS rated
• Air sealing at or below 3 ACH at SO Pa • Air sealing at or below 4 ACH at 50 Pa
• Ceiling insulation at or above R-49 • Ducts and air handler located inside conditioned space or duct
• Ducts and air handler located inside conditioned space or duct leakage to outside of less than 4 CFM25/100 ft2 CFA
leakage to outside of less than 4 CFM25/100 ft2 CFA • Furnace efficiency at or above 95% AFUE
• Furnace efficiency at or above 9711/c, AFUE
49
www.intgas.com/saveenergy
145

Energy
INTERMOUNTAIN®
GAS COMPANY 0 Efficiency
WHOLE HOME TIER I - $900 WHOLE HOME TIER II - $700
• HERS rated • HERS rated
• Air sealing at or below 3 ACH at 50 Pa • Air sealing at or below 4 ACH at 50 Pa
• Ceiling insulation at or above R-49 • Ducts and air handler located inside conditioned space or duct
• Ducts and air handler located inside conditioned space or duct leakage to outside of less than 4 CFM25/100 ft2 CFA
leakage to outside of less than 4 CFM25/100 ft2 CFA • Furnace efficiency at or above 95", AFUE
• Furnace efficiency at or above 97% AFU E
NEW OPTION: Stack the savings and stack the cash in your pocket! Layer water heating and/or smart thermostat rebates on top of the Whole Home
Tier I or Tier II rebate.
Example 1: Example 2:
Whole Home Tier 1 $900 Whole Home Tier II $700
Tier I Tankless Water Heater $325 Smart Thermostat $100
Smart Thermostat $100 Total Potential Rebate $800
50
Total Potential Rebate $1,325
146
www.intgas.com/saveenergy

RI Energy
INTERMOUNTAIN' Efficiency Commercial Energy Efficiency
GAS COMPANY 60
HEATING INCENTIVES
Eligible Appliance Efficiency Rating Rebate
Condensing Unit Heater 90;:: AFUE or Greater Efficiency $1,500
Boiler Reset Control N/A $350
High-Efficiency Condensing Boiler 90%or Greater Thermal Efficiency and 2300 kBTUh $4.50/kBTUh
KITCHEN EQUIPMENT INCENTIVES
Eligible Appliance Efficiency Rating Rebate
Fryer ENERGY STAR'5 Certified $800
Steamer ENERGY STARS Certified (2!38%cooking eff/!�2,038 BTU/hr/pan Idle Rate) $1,100
Griddle ENERGY STAR 51 Certified (>_38%cooking eff/<2,650 BTU/hr/pan Idle Rate) $200 51
147
ENERGY STAR R Commercial Food Service Product Finder

WHAT IS A CONSERVATION POTENTIAL ASSESSMENT (CPA) ?
Definition: A study estimating achievable energy savings through
efficiency measures.
Scope: Residential and Commercial
Types of potential :Tech n i cal, Economic, Achievable.
148

Strategic planning and regulatory compliance.
Supports Integrated Resource Planning (IRP) .
Inform IGC's EE goals, portfolio planning, and budget setting,
and identify new energy saving opportunities.
149

WHO CARES?
Resource PlanningTeam — reduction of natural gas consumption
due to increases in energy efficiency are a resource.
Energy Efficiency — Conservation Potential Assessment
identifies cost-effective energy saving potential
54
150

m
WHO CONDUCTS THE CPA?
GUIDEHOUSETEAM
torsi-
Jon Starr Neil Podkowsky Brian Chang Raniel Chan
Professional Project Manager Measure Lead Modeling Lead
Director Guidehouse Guidehouse Guidehouse
Guidehouse
55
151

2025 CPA
UPDATE
,a
M - r AV
152

CONSERVATION POTENTIAL ASSESSMENT 2025
Guidehouse conducted comprehensive study for the 2023 IRP
IGC did not have any program changes from the last study to
this one
Guidehouse updated model inputs for 2025 study, rather than
run another full-scale study
57
153

1 1 UPDATED
MODEL?
Global Input forecasts (market characterization) using new data from IGC:
Building Stock and Sales
Retail Rates
Avoided Costs
Inflation Rate
Discount Rate
Measure Inputs (savings, costs, and lifetimes) as applicable using IGC Technical Reference Manual (TRM)
Other Updates:
Extended the forecast period by two years
Shifted the starting year for adoption of Behavioral measures by two years, so the adoption trajectory now begins in 2025 instead of
2023.
58
154

WHATWAS UPDATED IN THE MODEL?
Building Stock and Sales: Compared to the 2023 CPA,
forecasted building stock is generally slightly higher
for commercial and modestly lower for residential
59
155

WHATWAS UPDATED IN THE MODEL?
Retail Rates: Compared to the 2023 CPA, rates are
lower for 2024=2025 but higher in 2026 and beyond

WHATWAS UPDATED IN THE MODEL?
Avoided Costs: Compared to the 2023 CPA, avoided
costs are lower in 2025 but higher in 2026 and beyond
61
157

WHATWAS UPDATED IN THE MODEL?
Inflation Rate: Now 3 .99%, previously 3 . 15%
Discount Rate: Now 2.68%, previously 3 .5 1 %
62

WHATWAS UPDATED IN THE MODEL?
Updated Measure Inputs (savings, costs, and lifetimes) as
applicable using IGC TRM v I .O. 27 out of the 120 measures
were updated.
63
159

WHATWAS UPDATED IN THE MODEL?
Other Updates:
Extended the forecast period by two years: it now goes out
to 2046 instead of 2044.
Shifted the starting year for adoption of Behavioral measures
by two years: adoption trajectory now begins in 2025
instead of 2023 .
64
160

Technical Potential
Total energy savings available by end-
use and sector, relevant to current
population forecast TYPES OF
Economic Potential POTENTIAL
Utility Cost Test (UCT) cost-
effectiveness
screen
Achievable
Potential
EE expected
to be
adopted by
programs

350
300TOTAL GAS ENERGY
E POTENTIAL BY
a, 250 `
POTENTIAL TYPE
200
(MM THERMS/YEAR)
c 150
m
0
a_
U 100
c
cn 50
0
2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2046
Technical —Economic —Achievable
162
66

ACHIEVABLE POTENTIAL FOR REBATE PROGRAMS
The EE savings that could be expected in response
to specific levels of program incentives and
assumptions about existing policies, market
influences, and barriers.
Estimated by:
Calculating the market share, or penetration of
measures based on customer awareness of the
measure and customer willingness to adopt the
measure
Willingness is determined by comparing payback time Achievable
associated with efficient measure against competing Potential
measures • " " •
to be
Calibrating forecast using historic program data adopted •
programs
67
163

350
300TOTAL GAS ENERGY
a, 250 POTENTIAL BY
POTENTIAL TYPE
200
(MM THERMS/YEAR)
c 150
m
0
a_
U 100
c
cn 50
0
2026 030 2032 2034 2036 2038 2040 204 2046
Technical —Economic —Achievable
164
68

Unconstrained Historical Budget:This
Business as Usual (BAU)•This scenario does scenario reflects a ramp up of customer adoption
• • of natural gas energy efficiency over a 10-year
• • not represent an intentionally defined change to
• • •. the model; it does reflect an assumption that future period from the start of the EE program (through
• program budgets will be closely correlated with 2029), driven by increased IGC program activity
•• IGC's historic EE program spending. without constraining program spending to historic
levels. Incentive levels are consistent with Business
as Usual Scenario.
Medium Adoption: This scenario increases the High Incentive, High Adoption:this scenario
reflects the savings possible by increasing the
adoption parameters compared to the incentives from 50% of measure incremental cost
unconstrained historical budget scenario and to 65% of incremental cost and further increasing
increases model parameter values relating to the customer awareness and willingness to adopt
customer awareness and willingness to adopt energy efficiency measures to the highest values
energy efficient technologies. Incentive levels are based on Guidehouse's experience and rules of
consistent with Business as Usual Scenario. thumb.
69
165

Gas Results - Residential, All Scenarios
zoo ALL
180
160 SCENARIOS:
a)
140
120 RESIDENTIAL
c
y 100 �
0
a
00 80
c
N 60
40
elm
20 now
2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046
—Technical —Economic Business as Usual
—Unconstrained Historic Budget Medium Adoption High Adoption, High Incentive
166
70

Gas Results - Commercial, All Scenarios
180 ALL
160
E 140 SCENARIOS:
L
120
OMME
CRCIAL
� 100
Y
C v 80
d
60 dw�
N
20 ago � do*
� ago
now
2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046
Technical -Economic Business as Usual
=Unconstrained Historic Budget Medium Adoption High Adoption, High Incentive
167
71

160
140 ACHIEVABLE
POTENTIAL
120 111111000
vFOR ALL
E 100
do
400 SCENAR O
80 I /
�o I
IS
c I
0 /
0
a 60op
00 /
c
M /
�n /
40 600
/
/
/
20 /
I
doop
I
0
2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046
Business as Usual —Unconstrained Historic Budget Medium Adoption High Adoption, High Incentive
168
72

COMPARISON OF 2023 AND 2025 STUDYACHIEVABLE
• 1
ANNUAL
1 GAS
SAVINGS
2.0
a�
1.8
t
1.6
1.4
ao
1.2
V)
1.0
C7
0.8
0.6
z
aJ) 0.4
z
0.2
c
Q 0.0
01 O N fM 193, Ln lD I- 00 Ql O T-1 fV rn IT Ln lD 1- 00 Q1 O r1 N m RT Ln lD
O O O O O O O O O O O O O O O O O O O O O
r4 PV PV N fV fV N N N N N N N N N N N fV N N N N N N N fV fV N
73
2023 Study (Business as Usual) —4--2025 Study (Business as Usual) --6--Historic Accomplishments
169

BIG
PICTURE
R TAKE-AWAYS
The combined effect of the global input updates was to generally increase Benefit-Cost ratios (UCT)
compared to the 2023 CPA, driven primarily by higher avoided costs in later years, combined with a lower
discount rate (the future is more important).
74
170

BIG
PICTURE
R TAKE-AWAYS
For "Business as Usual" scenario, achievable potential results are overall lower than the 2023
CPA, and the difference grow over time.
Incremental Achievable Potential(therms/yr)
BAU (Scen 1) 2024 2025 2026 2027 2028 2029 2030 2035 2040
2023 CPA Total 1,681,489 1,609,817 1.636.834 1.639.515 1,629,649 1.569.179 1.555,721 1.658,211 1,616.968
2025 CPA Total 1.435.954 1,563.629 1.325.611 1.219.682 1,232,025 1.217.600 1.164.390 973.022 836.745
Change -15% -3% -19% -26% -24% -22% -25% -41lr
2023 CPA Residential 1,656,777 1,582,970 1.607,031 1,606,593 1,593,441 1,529.423 1,511,952 1,587,032 1,497.466
2025 CPA Residential 1,420,173 1,537,652 1.297.384 1,188,569 1,198,097 1.180.763 1,124,447 910,776 733,919
Change -14% -3% -19% -2696 -25% -23% -26%
2023 CPA Commercial 24,712 26.848 29.804 32,921 36,208 39,756 43,769 71,179 119.502
2025 CPA Commercial 15,781 25,977 28.227 31,113 33,928 36,837 39,943 62,246 102.826
Change - -3% -5% •5% •6% -lab •9% •13% -14%
75
171

The measure competition group with the highest potential by
far is Residential Furnaces, which contains three measures:
Furnace 95 AFUE, Furnace 97 AFUE, and Gas Heat Pump (Space
Heating).
■ These together account for 1 .2 million therms of the achievable
potential for year 2024 (this was 1 .4 million therms in the 2023
BIC PICTURE CPA).
■ The key change with the 2025 CPA is that savings (and costs)
TAKE-AWAYS for the 95 AFUE and 97 AFUE furnaces were reduced by
approximately 75% per the IGC TRM. Additionally, the Gas
Heat Pump measure (which has much higher savings) is cost-
effective in more cases than previously, but the increase in
savings for Gas Heat Pumps is not quite enough to offset the
reduction from the Furnace measures.
172
76

BIG
PICTURE
R TAKE-AWAYS
■ In other scenarios, for example "Unconstrained" (Scenario 2), long-term potential is higher overall versus
the 2023 CPA.This is driven by an increase in Commercial sector potential, is the result of more measure
instances being modeled as cost-effective.
Incremental Achievable Potential(therms/yr)
Unconstrained (Scen 2) 2024 2025 2026 2027 2M 2029 2030 2035 2040
2023 CPA Total 1,831.708 1,844.290 2,035,668 2.308.830 2.714.656 3,338.038 3,869.440 4,567.530 4,863,836
2025 CPA Total 1,707.709 1.895.482 1.884,112 2.205,254 2.988.603 4,582.124 5,129.087 5,507.711 5.605,450
Change -7% 3% -7% -4% 10% 37% 33% 21% 15%
2023 CPA Residential 1,770.217 1.758,697 1.896.150 2.062.150 2,255.438 2.417.756 2.647.520 3,002.944 3,054.105
2025 CPA Residential 1.632,166 1,777,571 1.681.739 1,781.715 2,022,127 2,250.872 2.370,881 2,346,401 2,193,605
Change -8% 1% -11% -14% -10% -7% -10% -22% -28%
2023 CPA Commercial 61.491 85,593 139,518 246.681 459,218 920.282 1,221.921 1,564,586 1,809,730
2025 CPA Commercial 75.543 117.911 202,373 423.539 966,475 2.331,252 2,758,206 3,161,310 3,411,945
Change 23% 38% 45% 72% 1101i 120% 162% 89% 77
173

ACHIEVABLE
B
6% POTENTIAL BY
5% SECTOR AS A
PERCENT OF
4%
TOTAL SALES
c�
3%
m
2%
0)
0
1% BIG PICTURE, IT'S
0% PRETTYSTILL
2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2046
Commercial —Residential
174
78

WHAT'S NEXT?
IRP team to apply study results to resource planning.
IGC has filed an update to the Residential offering, that is still
an open case.
Proposing changes to the Commercial Program offering.
79
175

BREAK
80
176

SUPPLY & DELIVERY RESOURCES
ERIC WOOD
MANAGER, GAS SUPPLY

GAS SUPPLY PLANNING
What's the goal? To meet the energy needs and expectations of our customers:
Reliability (365 days per year)
Security (delivery on the coldest day)
Competitive and stable prices through a mix is fixed priced hedges
Efficiently meet future growth
Frequently evaluate the portfolio
82
178

NATURAL
R1 GAS
SUPPLIES
What are Traditional Supply Resources? What are Non-Traditional
Natural gas supply; the molecules or Supply Resources?
"commodity"
Renewable Natural Gas
Interstate pipeline capacity
Hydrogen
Storage facility capacity
Energy Efficiency
83
179

NATURAL
R1 GAS
SUPPLIES
Where Does "Our" Gas Come From?
Canadian gas supply (-V90%)
British Columbia
Alberta
Rockies' gas supply (- 10%)
Wyoming, Colorado, Utah etc.
Access to supply somewhat dependent upon available transport capacity
84
180

L, o* a
LowerBeaa 'I4
R,Y!r Hom River,Cordova
1 alit Laird aasms
Mcntney
I i Deep bash Muskwa,D er Park,
DIbi Ewe and Kli1a stales
` Phospe
CANADA
r_
Colorado Group
` Niobrara' I Frsftmk /
Heath" Bakken uuc orlon Bluff
North c° ;� �'
on
Mowry
American - Bane ••
Manco to Nibraro'
Margg ` USA S
New ( Marcellus
asI a s r.,� ,.,�,. , I I ,�-� k••n
p y er,[ur Harmo lie- tuel�Mulk�
1
L ' 7J odford Chatt
Mgrrtarey v a ttevtIle
_ Caney
nasauga
Current shale plays
Barnett- 0 Prospective shale plays
Woodford
a Basins
Stacked plays
Eagioroed,i —Shallowest oryouogeet
La Casita�
Sabtnas basin` — IntertneGa:e depth or ape
-� )Rurcos basin
Deepest or oldest
MEXICO Eagle Ford, Mixed shale and chalk play
Tily3nian ITamWcobasin •• Mixed shale and ktnesroneplay
••• Mixed shale and light dolostons-
�r Piniern, sihstoie-sands*one play 85
R ;m 2w km luxpan bas n�� amaulpas
U.S DEPARTMENT OF
VC mi Mane ®ENERGY

NATURAL GAS SUPPLIES
Gas Supply Forecast - Observations
Robust increase in shale gas production
Mature basins (WCSB, gulf on & offshore)
Today: ample supply vs demand
86
182

NATURAL GAS PRODUCTION BY PLAY 2008-2025
Monthly U.S. dry shale natural gas production by formation
billion cubic feet per day
100
90
Permian
80
70 Haynesville
60 Marcellus
Utica
50 Eagle Ford
40 Bakken
Barnett
30
20 Mississippian
10 Woodford
Rest of U.S.
0
2008 2010 2012 2014 2016 2018 2020 2022 2024
Data source: U.S. Energy Information Administration. Short-Term Energy Outlook. July 2025 e1d1
Source: EIA 87
183

U.S. NATURAL GAS CONSUMPTION BY SECTOR
Table 4.3 Natural Gas Consumption by Sector
Billion Cubic Feet
15,000
10,000
5,000
0
1950 1960 1970 1980 1990 2000 2010 2020
— Natural Gas Consumed by the Residential Sector
— Natural Gas Consumed by the Commercial Sector
— Natural Gas Consumed by the Industrial Sector, Total
Natural Gas Consumed by the Transportation Sector, Total
— Natural Gas Consumed by the Electric Power Sector
e11 Data source: U.S. Energy Information Administration 88
184 Source: EIA AEO2025

NATURAL
R1 GAS
SUPPLIES
Gas Supply - Pricing
Natural gas is a commodity and market is liquid
Price follows supply and demand fundamentals
Price history & forecast
89
185

■
RECENT HISTORIC GAS PRICES
Pacific Northwest Historic Index Pricing
S50.0000
Winter 22/23 Pipeline
Constraints/Low
545-0000
Storage
$40.0000
S35.0000
530.0000
525-0000
520 0000
Enbridge Pipeline
S15.0000
Rupture
$10-0000
55.0000
5- op Q1 Q1
to 1, N 00 O O O O O .--� .-1 .� N N M cn M V -zr In In t0 to tD f, N 00 00 00 as Ot O O -4 N N cn to M O V to
71 rl rl 111 1l r1 r-1 r1 r-1 e-1 71 r1 -1 1r 1l 'r rl .� r-1 N N N N N N N N N N N N N
CL
Z Q Io Z Q In Ir p Q Io Z Q to O 2 Q Io Z Q to O
SUMAS ROCKIES AEOD(USS) 90
r,
186

NATURAL
R1 GAS
PRICE
R FORECAST
Intermountain's IRP Price Forecast
Intermountain's long-term planning price forecast is based on a blend of current market
pricing along with long-term fundamental price forecasts.
The fundamental forecasts include sources such as Wood Mackenzie, EIA, the
Northwest Power and Conservation Council (NWPCC), Bentek and the Financial
Forecast Center's long-term price forecasts.
Used weighted prices from the sources based on historical performance, beginning
in year two of the forecast.
While not a guarantee of where the market will ultimately finish, Henry Hub
NYMEX is 100% of the forecast for the first year as it is the most current
information that provides some direction as to future market prices.
Intermountain is gathering Renewable Natural Gas information and plans to model RNG
as a potential resource in the upstream optimization process.
91
187

INTERMOUNTAIN'S IRP PRICE FORECAST
IGC Natural Gas Price Forecast (as of 5-7-2025)
$8.00
$7.00
$6.00 Preliminary
Weights:
$5.00 Sumas — 10%
o Rockies — 10%
$4.00 AECO — 80%
$3.00
$2.00
$1.00
$0.00
,ate �aJ ��Q �a� �aJ �eQ �a� �a� �e� ,ate �aJ �eQ ,ate �aJ ��Q
92
Sumas Rockies AEA® Weighted

INTERMOUNTAIN GAS COMPANY
2025-30 INTEGRATED RESOURCE PLAN
INTERSTATE TRANSPORTATION AND STORAGE RESOURCES
189

INTERSTATE TRANSPORTATION AND STORAGE RESOURCES
Intermountain holds firm, long-term contracts for
interstate capacity on four (4) pipelines - two U.S.
and two Canadian
All gas directly delivered to Intermountain comes
through the Williams Northwest system
Firm capacity on Northwest is determined at both
receipt and delivery points
94
190

INTERSTATE TRANSPORTATION AND STORAGE RESOURCES
Interstate Transportation Capacity — cont.
Delivery to Intermountain Service Territory
Firm Capacity Held Directly by Intermountain
City Gate Delivery Direct from Suppliers
Capacity Segmentation
Capacity Release and Mitigation for Intermountain
Market forces drive new capacity projects
95
191

Western••-� l t� -'`.�i�*.,�,
Canada-~' t;, w/ili/b s
SedimenA
NORTHWEST PIPELINE
Pipelines
� ` ",• Northwest Pipeline
GTN, NOVAAND
Other Pipelines
�Calga '�# +.h. Facilities
, Q Underground Gas Storage
OOTHILLS
an wIC.. Y�. �+ 0 Liquefied Natural Gas(LNG)
� .✓ ❑ Gas Processing Plant
Sumas — -
Q
Gas Producing Region
Ssaltle �` Spokane isMansinq�onnwam®aaasa�auoaMwa.aa
Date:3030+ Cwta In Arcview 32a
Wenatche Moses Lake Ke log
Jackson Lewiston _-
Prairie Plymout
II
Portland .•'�',•
Z
%.a
A Bas.m, Basii.
BaIN�"o Wind 1ilv :.
Basin
Grants Pass,, .•.
ee Opal Basin
' ivide w :
t SF'•...i ;{ Basin
an�.k:•Flb cl "sapin1A :r
a wash {
•-r• in
;�t„S LEI Uinpuiiiisiri r +•r j•
,Y.Y r: •• n
nacio
_ Basin 96

CAPACITY RESOURCES
Northwest Daily Maximum Transportation Capacity (MMBtu)
2025 2026 2027 2028 2029 2030 2031
Stanfield 224,565 224,565 2241565 2241565 2241565 224,565 224,565
Rockies 5%328 591328 591328 591328 591328 595328 5%328
Cityga to 1000 1000 10,000 10,000 101000 10,000 10,000
Total Capacity 2931893 293,893 293,893 2931893 2931893 2931893 293,893
Storage Withdrawals with Bundled Capacity 155,175 155,175 155,175 155,175 1551175 155,175 155,175
JP TF-2 Capacity 30,337 30,337 301337 30,337 30,337 301337 30,337
Nampa and Rexburg 35,500 35,500 351500 351500 351500 35,500 35,500
Maximum Deliverability 514,905 514,905 514,905 514,905 514,905 514,905 514,905
97
193

STORAGE RESOURCES
What is storage?
Natural or man-made structures where natural gas can be
injected and stored for later retrieval
Gas is normally injected during periods of lower demand
and lower prices
Gas is usually withdrawn during periods of higher demand
and higher prices
98
194

STORAGE RESOURCES
Why do we need storage?
Demand curve is not linear
➢ Annual supply curve somewhat linear
Transport capacity is very linear
➢ Not feasible to meet peak demand with only interstate
capacity and must-take gas purchases alone
➢ Storage enhances winter/peak delivery capability and
minimizes costs by balancing flat supply with seasonal
demands 99
195

Example Load Duration Curve
With Only Storage and Gas Supply
400,000
350,000
Storage W ithdrawals
300,000 Transport Capacity
y Storage Injections
c 250,000
m 200,000
150,000 IF
100,000
50,000
0
1 25 49 73 97 121 145 169 193 217 241 265 289 313 337 361 I00

STORAGE RESOURCES
Uses
"Needle" peaking
Winter baseload
Day-to-day load balancing
Natural gas price hedge
➢ System integrity/emergency issues
Types
Liquefied Storage (LNG)
Underground
101
197

STORAGE RESOURCES
Liquefied Storage Characteristics
Natural gas is liquefied @ minus 2600 F
Liquid occupies 1 /600 volume of vapor
Nearly pure methane, non-corrosive, non-toxic and
yes, SAFE
High regasification/withdrawal capability
Ideal for needle peaking, system balancing and
system integrity issues
102
198

STORAGE RESOURCES
Liquefied Storage Characteristics
Liquefaction is slow which limits ability to cycle
inventory
Liquefaction is energy intensive 4 high cycling
and inventory cost
Generally stored in above-ground tanks
No methane is released into the atmosphere
103
199

PLYMOUTH LNG FACILITY
�r.

STORAGE RESOURCES
Underground Storage Characteristics
Gas is injected under pressure into developed salt domes,
depleted well structures, underground aquifers or other
porous geological formations
Maximum daily withdrawal less than liquid storage;
operating capability is dependent upon inventory level and
pressure
Injections comparatively faster and cycling costs are lower
than liquid storage; multiple inventory cycles can enhance
cost effectiveness
105
201

STORAGE RESOURCES
Location & Type of Storage used by Intermountain
Nampa, ID LNG — liquid (Intermountain)
Plymouth,WA LNG — (Northwest Pipeline)
Rexburg, ID Satellite LNG (Intermountain)
Jackson Prairie - underground aquifer in western
WA (Northwest Pipeline)
Clay Basin - underground depleted well reservoir
in NE Utah (Questar Pipeline)
106
202

STORAGE RESOURCES - LOCATIONS
a..et
WLjrd Gm Swam';Areas
wdsl Von
SPpKANE • KdoV
JP SU La.,Wn
Plymouth LS
Rexburg
��. 7j'Z W'yOrrtlnp
1Ao�ad GMW ANN Nun
i 107
203 •sKrw�crtr ---Cay Basin
wee.a.r+

STORAGE RESOURCES
Intermountain's 2023/24 Storage Statistics (MMBtu)
Daily Withdrawal Daily Injection
Seasonal % of Redelivery
Facility Capacity Nov-Mar Maximum % of Peak Max Vol # of Days Capacity
Nampa 600,000 1% 60,000 16% 3,500 166 None
Plymouth* 1,475,135 4% 155,175 43% 12,500 213 TF-2
Jackson Prairie 1,092,099 3% 30,337 8% 30,337 36 TF-2
Clay Basin 8,413,500 20% 70,114 19% 70,114 120 TF-1
108
204
Grand Total 2$% 86%

Sample LDC with Efficient Mix of All Supply Resources
450
400
Storage Not Needing
35o Interstate
Citygate Delivered Transport Capacity
300
250 Storage & Winter Gas Needinq Interstate
200
o Year round Gas
150
m
� 100
50
0
1 15 29 43 57 71 85 99 113 127 141 155 169 183 197 211 225 239 253 267 281 295 309 323 337 351 365
Days
109
205

QUESTIONS ?

FEEDBACK
MISSIONS
■
[e-mail]
Please provide comments and feedback within 10
days
207

THIRD MEETING
September 17, 2025, 9:00 a.m. - Noon
Potential Capacity Enhancements
Resource Optimization
Planning Results
Remaining IRP Process
112
208

IGRAC #2
INTERMOUNTAIN""
GAS COMPANY
A Subsidiary of MDU Resources Group,Inc.
RESOURCEINTEGRATED
INTERMOUNTAINAUGUST 13.2025
.URCE ADVISORY COMMITTEE
Date &time: 8/13/2025, 9:00 AM to 11:00 PM MT
Location: Microsoft Teams Meeting
Presenters: Kathleen Campbell, Kathy Wold, Brian Robertson, Eric Wood
In attendance: Bailey Steeves, Brian Robertson, Chris Robbins, Eric Wood, Jason Talford,
Jenny DeBoer, Kathleen Campbell, Kathy Wold, Mark Sellers-Vaughn, Matthew
Hunter, Michael Parvinen, Rebecca Wildman, Ryan Denton, Seungjae Lee, Vicki
Stephens, Zachary Harris, Zachary Sowards
Introduction
Brian Robertson, Manager of Supply Resource Planning, opened the meeting by welcoming and thanking
stakeholders for participating in Intermountain's IRP Process. Brian then proceeded with introductions,
the agenda, a safety moment, and a reminder of the stakeholder engagement goals.
Presentation #1 — Distribution System Modeling (Kathleen Campbell)
• System Dynamics of Piping and Facilities
• Synergi Gas is the model Intermountain uses to evaluate predicted flows and pressures during
peak weather events
• Discussed the process of building out the models
o Rebuilt every 3 years, most recently in early 2025
• Customer Management Module (CMM) uses Customer Care & Billing and weather data to build
regression models.
• Kathleen then covered the capabilities of the Synergi model once the models are built out
o Review large volume customer requests, future planning based on IRP growth, and
determining system reliability to name a few
• Described enhancement options
o Pipeline, facility upgrades, additional regulator station, new citygate station, additional
compressor stations
• Discussed enhancement considerations and selection guide
Presentation#2—Avoided Cost Methodology (Brian Robertson)
• Brian gave a brief update to the history of the avoided cost model
Page 1 of 2
209

• Explained that the avoided cost is the cost to serve a dth of gas, which will be evaluated to
determine if there is an energy efficiency program that could replace that dth of gas at a lower
cost.
• Provided the formula and explained the inputs to the cost
o Commodity Cost, Transportation Cost
o Distribution Costs, although $0 for now
Presentation #3— Energy Efficiency (Kathy Wold)
• Kathy provided insights to current rebates and incentives
• Explained what the Conservation Potential Assessment and its importance
• Discussed the updates to the conservation potential and changes from the 2023 IRP
o Main updates included building stock and sales, retail rates, avoided cost, inflation rate,
and discount rate
Question: "What is the reason for the decline in the discount rate?"
Answer: Brian stated that"Intermountain will have to get back to you on this."After further
digging, the reason is that the discount rate is impacted by the change in the
inflation rate.
There was dialogue between the CPA and how Energy Efficiency is modeled in the IRP.
Ultimately, Intermountain would require investing time to incorporate some modeling that's never
been done, so implementing it into this IRP may be difficult. IGC has reached out to Staff to
discuss this further.
• Kathy discussed technical, economic, and achievable potential
• Intermountain has four scenarios, the base business as usual, unconstrained historical budget,
medium adoption, and high incentive, high adoption. Kathy provided the projections for each
scenario.
• Finally, Kathy provided the big picture take-aways from all the updates for the 2025 IRP
Presentation #4—Supply Resources and Transportation &Storage Resources (Eric Wood)
• Eric provided a background of gas supplies around North America
• Discussed historical pricing, what can impact those prices, and provided a price forecast for the
IRP
• Eric then shared the Company's current transportation and storage resources to serve customers
Question: "Has the pipeline ever run out of gas?"
Answer: "Not over a large area but in certain instances, some small areas of pipe can be
constrained for different reasons."— Eric Wood
The Meeting was Adjourned— IGRAC#3 will be held on September 17, 2025 @ 9 AM MT
Page 2 of 2
210

ltlmrER
AI:DLI
0
4T)
liq
GAS COMPANY
A Subsidiary of MDU Resources Group, Inc.
INTEGRATED RESOURCE PLAN
211
SEPTEMBER 17, 2025
INTERMOUNTAIN GAS RESOURCE ADVISORY COMMITTEE (IGRAC)

•
m I
■ Introductions
■ Feedback Process
■ Agenda

FEEDBACK
MISSIONS
■
■ [e-mail]
■ Please provide comments and feedback within 10 days
213

1 . 1
Welcome & Introductions — Brian Robertson (Manager, Supply Resource Planning)
Safety Moment — Brian Robertson (Manager, Supply Resource Planning)
Load Demand Curves — Ryan Denton (Resource Planning Economist)
Potential Capacity Enhancements — Kathleen Campbell (Senior Engineer)
Resource Optimization — Brian Robertson (Manager, Supply Resource Planning)
Questions/Discussion
214

Demand Supply & Delivery Resources
Economic Overview Transportation
Capacity & Storage
. Distribution System
Residential & Commercial LINaturalOverview
Customer Growth Gas Supplies
Design
Non-Traditional
Residential & Resources
Weather Energy Efficiency:
Commercial Usage
Per Customer --------------------=--- Residential &
Commercial
Industrial Demand
Demand Supply & Deliverability
Load Demand Curves
Optimization Modeling
System
Enhancements
Demand
215

BRIAN ROBERTSON
MANAGER, SUPPLY RESOURCE PLANNING

Ligioit 'ingsI ovvPirotectrurself
If you hear thunder and sL�t shelter righen possible.
Listed below are several tips before, during, and aft a storm:
DURING THE STORM
BEFORE THE STORM
• • seeking shelter in sheds, picnic shelters,
covered " tents or low, If planning any outdoor activities; check under
Wait out - storm in a substantial
weather forecasts and alerts. building or hard-topped vehicle with
• Cancel or postpone if bad windows rolled up. AFTER THE STORM
weather seems likely.
Avoid = ground, "e ' Charges of lightning can linger in
Make a lightning safety plan that the clouds; stay indoors for at
Includes where to seek shelter and the Stay away from metalobjects; they . • not
safest route to get there. attract lightning, but conducts it. least 30 minutes after the last
sound of thunder.
Unplug electrical items to avoid power Keep clear of doors an• windows.
surges.
Plumbing
•- Bring family pets indoors or put them the stormpasses to shower or • •
into a fully enclosed building.
fishing,If return to shore and seek a safe \ i '
shelter as soon as possible.
Article Reference: Druley, Kevin.,"Protect yourself from lightning" Family Safety& Health Fall 2019. Print.

RYAN DENTON
RESOURCE PLANNING ECONOMIST

LOAD DEMAND CURVE KEYVARIABLES
Customer usage per degree day.
Low, base and high growth core market customer count projections.
`Design weather' conditions.
Demand-side management (DSM).
Maximum daily flow quantity (MDFQ) for large volume customers.
219

PEAK SEASON CORE MARKET LOAD DEMAND CURVE
METHODOLOGY
Usage per - per Residential & Commercial
t HDD
Degree Total Daily Usage
Residential & Commercial
Total Daily Usage
Demand-Side Management
Large Volume MDFQ
Total Dai I U sa e
y g

LOAD DEMAND CURVE
Load demand curve: A forecast of daily gas demand using weather normal, `design
temperatures', customer counts, and forecasted usage per customer.
Designed to measure demand to compare to distribution capacity at our 5 areas of
interest (A01).
To measure total company demand for upstream capacity decisions.
Based on current resources or resources scheduled to be available during the IRP
period.
Remedies for any constraints will be identified later.
Storage management.
221

2025 Load Demand Curve
Design Base Case
Total Company
700,000 -
600 000 Peak Day 536,800 Dth
- - - - - - - - - - - - - - - -
500,000
400,000
s
0
300,000
200,000
100,000
10/1/2025 11/1/2025 12/1/2025 1/1/2026 2/1/2026 3/1/2026 4/1/2026 5/1/2026 6/1/2026 7/1/2026 8/1/2026 9/1/2026
Core+LV-1 Demand less DSM — — Maximum Transport Deliverabiitywith LNG — — Maximum Transport Deliverability
222

2030 Load Demand Curve
Design Base Case
Total Company
700,000
600000 Peak Day 582,518 Dth
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
500,000
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
400,0()0
L
300,000
200,000
I
100,000
10/1/2030 11/1/2030 12/1/2030 1/1/2031 2/1/2031 3/1/2031 4/1/2031 5/1/2031 6/1/2031 7/1/2031 8/1/2031 9/1/2031
Core+LV-1 Demand less DSM — — Maximum Transport Deliverability with LNG — — Maximum Transport Deliverability
223

Idaho Falls Lateral
Sun Valley Lateral
Canyon County Lateral
State Street Lateral
Central Ada County
224

2025 Load Demand Curve
Design Base Case
Idaho Falls Lateral
120,000
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
100,000
80,ODO
83 83 60,000
40,000
20,000
10/1/2025 11/1/2025 12/1/2025 1/1/2026 2/1/2026 3/1/2026 4/1/2026 5/1/2026 6/1/2026 7/1/2026 8/1/2026 9/1/2026
Demand less DSM — — Ma)dmum Physical Deliverability — — MaArnum Physical Deliverability with LNG Storage
225

2030 Load Demand Curve
Design Base Case
Idaho Falls Lateral
120,000
- - - - - . - - - - - - - - - -
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
100,000 —
80,000
0 60,000
40,000
20,000
10/1/2030 11/1/2030 12/1/2030 1/1/2031 2/1/2031 3/1/2031 4/1/2031 5/1/2031 6/1/2031 7/1/2031 8/1/2031 9/1/2031
Demand less DSM — — Maximum Physical Deliverability Maximum Physical Deliverability with LNG Storage
226

2025 Load Demand Curve
Design Base Case
Sun Valley Lateral
30,000
25,000 — — — — — — — — — — — — — — — — — — — — — — — — — — — —
20,000
15,000
10,000
5,000
10/1/2025 11/1/2025 12/1/2025 1/1/2026 2/1/2026 3/1/2026 4/1/2026 5/1/2026 6/1/2026 7/1/2026 8/1/2026 9/1/2026
Demand less DSM — — Maximum Physical Deliverability
227

2030 Load Demand Curve
Design Base Case
Sun Valley Lateral
30,000
25,000 - - - - - - - - - — — — — — — — — — — — — — — — — — — —
20,000
o 1-5'000
10,000
5,000
10/1/2030 11/1/2030 12/1/2030 1/1/2031 2/1/2031 3/1/2031 4/1/2031 5/1/2031 6/1/2031 7/1/2031 8/1/2031 9/1/2031
Demand less DSM — — Maximum Physical Deliverability
228

2025 Load Demand Curve
Design Base Case
Canyon County Lateral
160,000
140,000 — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — —
120,000
100,000
o 80'000
60,000
40,000
20,000
10/1/2025 11/1/2025 12/1/2025 1/1/2026 2/1/2026 3/1/2026 4/1/2026 5/1/2026 6/1/2026 7/1/2026 8/1/2026 9/1/2026
Demand less DSM — — Maximum Physical Deliverability
229

2030 Load Demand Curve
Design Base Case
Canyon County Lateral
160,000
140,000 — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — —
120,000
100,000
80'000
60,000
40,000
20,000
10/1/2030 11/1/2030 12/1/2030 1/1/2 031 2/1/2 031 3/1/2 031 4/1/2 031 5/1/2 031 6/1/2 031 7/1/2 031 8/1/2 031 9/1/2 031
Demand less DSM — — Maximum Physical Deliverability
230

2025 Load Demand Curve
Design Base Case
State Street Lateral
90,000
80,000 — — — — — — — — — — — — — — — — — — — — — — — — — — —
70,000
60,000
50,000
s
0
40,000
30,000
20,000
10,000 r.
A P/
10/1/2025 11/1/2025 12/1/2025 1/1/2026 2/1/2026 3/1/2026 4/1/2026 5/1/2026 6/1/2026 7/1/2026 8/1/2026 9/1/2026
Demand less DSM — — Maximum Physical Deliverability
231

2030 Load Demand Curve
Design Base Case
State Street Lateral
100,000
90,000
80 000 — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — —
70,000
60,000
o 50'ODO
40,000
30,000
20,000
10,000
10/1/2030 11/1/2030 12/1/2030 1/1/2031 2/1/2031 3/1/2 031 4/1/2031 5/1/2031 6/1/2 031 7/1/2031 8/1/2031 9/1/2031
Demand less DSM — — Maximum Physical Deliverability
232

2025 Load Demand Curve
Design Base Case
Central Ada Lateral
100,000
90,000
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
80,000
70,000
60,000
50'000
40,000
30,000
20,000 JL
10,000 AL A
10/1/2025 11/1/2025 12/1/2025 1/1/2026 2/1/2026 3/1/2026 4/1/2026 5/1/2026 6/1/2026 7/1/2026 8/1/2026 9/1/2026
Demand less DSM — — Maximum Physical Deliverability
233

2030 Load Demand Curve
Design Base Case
Central Ada Lateral
100,000
90,000
80,000
70,000
60,000
p 50,000 �v
40,000
30,000
20,000 At
10,000
10/1/2030 11/1/2030 12/1/2030 1/1/2031 2/1/2031 3/1/2031 4/1/2031 5/1/2031 6/1/2031 7/1/2031 8/1/2031 9/1/2031
Demand less DSM — — Maximum Physical Deliverability
234

QUESTIONS ?

DISTRIBUTION SYSTEM ENHANCEMENTS
KATHLEEN CAMPBELL, P.E. - SENIOR ENGINEER - ENGINEERING SERVICES
ZACHARY SOWARDS - SENIOR ENGINEER- ENGINEERING SERVICES

IGRAC #2 COVERED:
System dynamics
Synergi model process
Identification of system deficits/constraints
Distribution enhancement/reinforcement options to address deficit
Enhancement considerations and selection process into 5-year budget
237

THIS PRESENTATION WILL COVER:
Project needs to support core growth for each AOI
Alternative Analysis to resolve deficit (if it has not already been covered in a previous IRP)
Timing, Cost and capacity gained for each project/alternative.
238

AREAS OF INTEREST (AOI)
NATURAL GAS SYSTEM
r INTERMOUNTAIN GAS COMPANY
' CAW WN GA5
■ Distribution System Segments: ,VON
■ Canyon County EOON
APeA_ w ONTO -_
Of NAP =
PATETTE �� `BANTNONT
■ Central Ada County Lateral :",,,,LAND. •NEW PLvNOUT CALIF. NEVADA UTAH
CITY
PASTAR a"
NN11_ �
"North of State Street" Lateral IFTON ; AEBMN ant INO
w I. ��a CITE' SON VALLEY ►lWISNLL! RIGBY
` r KOOIUN!Fl MORN
■ Sun Valley Lateral �'• 'X ' VAILEY IONA
o'NOPAus:: �
S I- TEL-EVUE BMELLE-
• LT Idaho Falls Lateral „._�■ ,� NOAELAN
a KAC
P°"T
CANYON
■ -_� L—_ 0000N I 1 6NOnE AOLROCLN
All Other Customers 4yEq f�,! POCArTtic4 rQ
• IcAp FAQ IWON v YS
t Ja'� • tCOA�nINGS
Yt CAIAION
1W E>1MU R81 v tET �UEGLO
Lt6t AAII.VO•
CRIE •GEORGE.'TOW11
�u uN:I1•ta at ►MIAL TA
PRF0MCI,WAA1 QAA CO WRWE W"ALS MCNTPFI.IFN
• T:1404 UW.ED•W NTERNCIMTAROAS CO
O WOL" 7UNTAN ILASCO.UPPKZ!
>�• ;%PMFR
1
239
�.r

■
Reinforcements required to meet 2030 growth predictions
Caldwell Reinforcement — Chinden (HWY 20) from to Prescott Lane to Middleton Road
2027
New Plymouth Gate Upgrade
2027
240

CANYON COUNTYAOI
■ No reinforcements required to meet 2030 IRP growth predictions
■ AOI Update
■ Ustick Phase 3 was completed in December 2024.
241

STATE
STREET
LATERAL
R1 1 •
Requires reinforcements by 2026 & 2027 to meet IRP growth predictions
AOI Capacity Limiter: 12-inch HP bottleneck on State Street and 4 in HP bottleneck on Linder Rd & State Penn
(Boise #2) Gate Capacity
Alternatives considered for 12-inch HP & 4- HP bottleneck were discussed in 2021 IRP
State Street Phase II Uprate was selected in 2021 IRP and is budgeted for 2026
State Penn Gate Upgrade is budgeted for 2026 Design and 2027 Construction
242

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243

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244

CENTRAL . COUNTY
•
No reinforcements required to meet 2030 IRP growth predictions
AOI Update
12-inch South Boise Loop was completed in 2023
245

SUN VALLEY
LATERAL
R1 1 •
No reinforcements required to meet 2030 IRP growth predictions
AOI Update
Shoshone
Compressor
Shoshone Compressor was completed in 2023 --Station
y
r
Jerome Compressor
Sation
246

. 1 • FALLS LATERAL
R1 1 •
Requires reinforcements by 2030 to meet IRP growth predictions.
AOI Capacity Limiter: Suction line pressure to the Wapello Compressor
Wapello Compressor Station expected to be operational in 2026
247

. • FALLS •
MER
SUaAR£I7X
RE>L(Q�URG
MENAN
LENISVI E
RIGBY
RIRIE
UCON
IONA
Iloaho�a ils S '
MON
s
S E
IFl
MORE( NO
BIA
FORT LL `t
1
CHUBB K
• C
P •EL10
_ INKOM
248

WAPELLO COMPRESSOR / •
9
SHE 'EY
Blackfoot ,
zc Mountain
FIRTH
�51
MORELAND
• GROVELAND
9ingharr Nridge
RIVERSIDE
• �BLA�/wCF T
249

. • FALLS COMPRESSOR
SUCTION PIPELINE 2030
SHE 'EY
261, Blackfoot
Mountain
RR,Ti f
40
MORELAIND
• GROVLLAND
Bingham
andye
RNERSIDE
' LBLA,CKF
250

AOI CAPACITY SUMMARY AND TIMING NEEDS:
Ada State Street Canyon Canyon Countyrateral
n Valley
Ada County State Street Lateral Sun Valley AOI Idaho Falls Later
CountyA01 Lateral AOI County AO AOI AOI o Falls AO
AOI Capacity AOI Reinforcement Reinforcement AOI Capacit
Reinforcemen Capacity Capacity Reinforcem pacity forcement Req
(th/day) q ( / y) Required ( / y) q day) Required (th/day)
t Required th da th da Required
1 . 1 111 • - 1 111State Street Uprate •1 111 • - 11 • - 1 111I FL CompressorStation
State Penn Gate
1 : 1 111 Upgrade •1 111 • - 11 • - 1 111 •
1 : 1 111 • - • 1 111 • - •1 111 • - � 11 • - 1 111 • -
1 • : 1 111 • - Me
• - •1 111 • - 11 • - 1 111 •
/ / : 1 111 • - M111 • - •1 111 • - 11 • - 111 •

QUESTIONS ?

IRP OPTIMIZATION MODEL
Draft Design Base Results

:
:
Demand Supply & Delivery Resources
:
Transportation, T
Economic OverviewDistribution
• LCapacity & Storage System Overview
Residential & Commercial
Industrial Demand Non-Traditional
Customer Growth Natural Gas
• Supplies
Resources
Design Weather
1 '
Design Residential & Energy Efficiency —
Commercial Usage .
R&C
1 '
Demand Supply & Deliverability
ILoad Demand Curves
Optimization Modeling
System Enhancements

IRP OPTIMIZATION MODELING
IGC IRP Model "Integrates"/Coordinates all the main functional elements of IGC
operation:
Gas Demand/Load, how much & where is gas consumed,"Load Duration Curve" (LDC) by area of
interest.
Gas Supply, from where, how much, and what price is gas supplied to meet demand (LDC).
Gas Transport, how does gas move from supply to demand area given pipeline size and prices.
Demand Side Management (DSM), cost effective energy efficiency is used to reduce demand
Local Gas Distribution, local lateral sizing is explicitly modeled to meet demand & ensure reliability
The IRP model utilizes PLEXOS®, a linear optimization model, to determine the least cost manner
to have loads served by supply, transport, DSM & laterals.
All results presented here are draft subject to further IGC review.
255

WHAT IS OPTIMIZATION ?
Utilizes a standard mathematical technique called "linear programming" . . .to
optimize over all possible combinations.
The model knows the exact load and price for every day of the planning period
based on the analyst's input and can therefore minimize costs in a way that would not
be possible in the real world.
Therefore, it is important to recognize that linear programming analysis provides
helpful but not perfect information to guide decisions.
Selects from a mix of resources over planning horizon to meet forecasted loads.
256

MODEL ELEMENTS
Functional components:
Demand forecast (Area's of Interest)
Traditional supply resources
Existing and potential gas supplies by basin
Storage resources
Transportation capacity resources
Price forecast
Non-traditional supply e.g., new distribution capacity, RNG, DSM etc.
257

Woctorn
C:anadian
Station 2 Swdirviontary
C.
.fors
tie1Wlb
r AE O
sum
Cm
Kl�t�sy�ts
Stan told
Me In Roby
,
�ortba.ftt Ap.lu. Opal
XAs Rnv Rocks**
Basin%
�� 25

r
MODEL 'ram,. ` _Ll_/ r ��' - `v`�M� •`!a
_—\
STRUCTURE I A 131�;
•Van uver
4 i 16
Slumas Kingsgate
I
Transport, Storage, pp • the
Demand • IdahoWA ING70N
ne
T coma = u ^
�; MO
Helena
JP IC
+--------------
Port nd
PLY 3
.5wnneld
;alem ;,
i gene OREGON
YNampa Street NC ,Sun Valley NC Idaho Falls NC
_.... .'Wa NC -
r -
L
f,�4 - -
w C Rexburg NC
-----' ---- .... ------ ---------------- = -•--------
-- ) Great Sal• Opal
Clay IC
259

MODELTransportation contracts are the means
of how Intermountain gets the gas from
STRUCTURE the supplier to the end user.
Transportation has an MDQ, a "E`
Reservation Charge (D I rate), a Flow
Charge (transportation rate), and a fuel
.. . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
loss percentage.
. . .. . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . .
• • A maximum delivery quantity (MDQ)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
which is the maximum amount of gas
Intermountain can move on the pipeline ii
on a single day.
• A D I rate which is the reservation rate
to have the ability to move the MDQ
amount on the pipeline.
• A transportation rate which is the rate
per dekatherm that is actually moved on
the pipeline.
• 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 citygate.
260

Intermountain has storage at 5
MODEL locations:Jackson Prairie OP), Plymouth
STRUCTURE (Ply), a Basin, Nampa, and Rexburg.y) Clay Bi N p g PLY 1
• Storage injections targets are set at . . . . /
35% by the end of June, 80% by the end
of August, and 100% by the end of . . . PLY 2
September to emulate cycling storage . . . . .
Storage for non-needle peaking storage.
PLY 3
Intermountain can withdrawal - . . ' . . ' '
approximately 30,377 dth per day from `
JP, 155, 175 dth per day from Plymouth,
and 70, 144 dth per day from Clay Basin
for a total of approximately 255,626
dth per day of off-system storage.
• Intermountain can withdrawal
approximately 50,000 dth per day from
Nampa and 5,500 dth per day from
Rexburg for a total of approximately
55,500 dth per day of on-system
storage.
261

MODEL • Intermountain can purchase gas
at three markets; AECO,
STRUCTURE SUMAS, and OPAL. . . • . . . . . . . . . .
• At each market Intermountain
can purchase gas at different . . . . . . 16
locations along the pipeline. . . . . AECO . . . . . .
Supply • For each year, Intermountain • • • • • . • •
uses Base,Winter base, . . . . . . . .
Summer and Winter day gas,
and Peak day incremental
supplies as inputs.
• Over the planning horizon, the
contracts are renewed in
November and April.
262

MODEL
STRUCTURE
Total Supply
500,000
450,000
400,000
Supply 350,000
300,000
(A Core Demand less DSM
E
......Base Supply
m 250,000
———Winter Base
v
200,000 Winter Day
• Summer Day
150,000 — —Peak Supply
100,000
50,000
OHO OHO OHO O�y Off~ O�y O�y O�1 O�1 O�y O�y O�y
1o\ti�ti 1y\ti�ti ti��y\� y\ti�ti �\ti�ti 3\ti�ti �\ti�ti �\ti�ti �\ti�ti �\ti�ti �\ti�ti �\ti�ti
263

MODEL Demand is forecasted at the five areas of interest, as
well as all other customers.
STRUCTURE • Demand is determined by the load demand curves.
• Each area of interest has DSM, which decrements
demand at the avoided cost price.
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Demand Area
Rexburg
Idaho Falls-core Idaho Falls Idaho Falls NC Idaho Falls-non core
12
t- ! ya'
Sun Valley-core �S6. alley I Sun Valley NC Sun Valley-non core
- ` .
i All Other core Al Other 'All Other NC All Other-non core
`�
IGC ` . or ^ . IGC NC '
Central Ada-core Central Ada Central Ada NC 'Central Ada-non core •
Canyon County-core anyon County Canyon County NC-'Canyon County-non core
State Street-core IN,N State Street N State Street NC State Street-non core
. . . . . . . . . . . . . . . . . . .
264

Lateral Capacity Summary By Year,Weather:Design,Growth:Normal
2025 Base Year(Dth)
%of Existing Planned Capacity Existing+ %of Existing+
Area of Interest Total Peak Day Existing Capacity Capacity Upgrade Upgrade Capacity Upgrade Capacity
IDAHO FALLS 86,121 90,400 95% 18,900 109,300 79%
SUN VALLEY 19,994 20,000 100% 4,750 24,750 81%
CANYON COUNTY 101,399 103,200 98% 35,800 139,000 73%
STATE STREET 75,346 82,000 92% - 82,000 92% DRAFT
MODEL
CENTRALADA 72,996 74,500 98% 12,500 87,000 84%
ALL OTHER 276,942 RESULTS
2026 Year 2(Dth)
Planned Capacity Existing+ %of Existing+
Area of Interest Total Peak Day Existing Capacity %of Capacity Upgrade Upgrade Capacity Upgrade Capacity LATERALS
IDAHO FALLS 86,555 109,300 79% 109,300 79%
SUN VALLEY 20,247 24,750 82% 24,750 82%
CANYON COUNTY 104,221 139,000 75% 139,000 75%
STATE STREET 76,953 82,000 94% 82,000 94%
CENTRALADA 74,489 87,000 86% 87,000 86%
ALL OTHER 280,541
2027 Year 3(Dth)
Planned Capacity Existing+ %of Existing+
Area of Interest Total Peak Day Existing Capacity %of Capacity Upgrade Upgrade Capacity Upgrade Capacity
IDAHO FALLS 88,310 109,300 81% 109,300 81%
SUN VALLEY 20,497 24,750 83% 24,750 83%
CANYON COUNTY 107,241 139,000 77% 139,000 77%
STATE STREET 78,362 82,000 96% - 82,000 96%
CENTRALADA 75,984 87,000 87% - 87,000 87%
ALL OTHER 283,670
265

2n28 Year4(Dth)
Planned Capacity Existing+ %of Existing+
Area of Interest Total Peak Day Existing Capacity %of Capacity Upgrade Upgrade Capacity Upgrade Capacity
IDAHO FALLS 89,942 109,300 82% 109,300 82% DRAFT
SUN VALLEY 20,740 24,750 84% 24,750 84%
CANYON COUNTY 110,237 139,000 79% 139,000 79%
STATE STREET 79,870 82,000 97% 82,000 97% MODEL
CENTRALADA 77,478 87,000 89% 87,000 89%
ALL OTHER 2,37,240
2n29 Year S(Dth) RESULTS
Planned Capacity Existing+ %of Existing+
Area of Interest Total Peak Day Existing Capacity %of Capacity Upgrade Upgrade Capacity Upgrade Capacity LATERALS
IDAHO FALLS 91,611 109,300 84% 109,300 84%
SUN VALLEY 20,984 24,750 85% 24,750 85%
CANYON COUNTY 113,068 139,000 81% 139,000 81%
STATE STREET 81,379 82,000 99% 82,000 99%
CENTRALADA 78,974 87,000 91% 87,000 91%
ALL OTHER 291,026
Year 6(Dth)
Planned Capacity Existing+ %of Existing+
Area of Interest Total Peak Day Existing Capacity %of Capacity Upgrade Upgrade Capacity Upgrade Capacity
IDAHO FALLS 93,230 109,300 85% 109,300 85%
SUN VALLEY 21,224 24,750 86% 24,750 86%
CANYON COUNTY 115,926 139,000 83% 139,000 83%
STATE STREET 82,892 82,000 101% 82,000 101%
CENTRALADA 80,473 87,000 92% 87,000 92%
ALL OTHER 294,269
266

DISTRIBUTION SYSTEM SHORTFALL SOLVESAND
UPGRADES
ADA County — Bend 12-inch S Boise Loop
State Street — State Street Uprate and State Penn Gate Upgrade
Canyon County — 12-inch Ustick Phase III
Sun Valley Lateral — Shoshone Compressor Station and Suction line pressure to the Wapello Compressor
Idaho Falls — IFL Compressor Station
267

TRANSPORTATION SHORTFALL SOLVES
■ Contract Renewals
■ Rockies Connector
■ Alternative Transportation Uptake
■ Renewable Natural Gas
■ Others?
268

Lateral Capacity Summary By Year,Weather:Design,Growth:Normal
2025 Base Year(Dth)
%of Existing Planned Capacity Existing+ %of Existing+
Area of Interest Total Peak Day Existing Capacity Capacity Upgrade Upgrade Capacity Upgrade Capacity
IDAHO FALLS 86,121 90,400 95% 18,900 109,300 79%
SUN VALLEY 19,994 20,000 100% 4,750 24,750 81%
CANYON COUNTY 101,399 103,200 98% 35,800 139,000 73%
STATE STREET 75,346 82,000 92% - 82,000 92% DRAFT
MODEL
CENTRALADA 72,996 74,500 98% 12,500 87,000 84%
ALL OTHER 276,942
- RESULTS
?=i?6 Year 2(Dth)
Planned Capacity Existing+ %of Existing+
Area of Interest Total Peak Day Existing Capacity %of Capacity Upgrade Upgrade Capacity Upgrade Capacity LATERALS
IDAHO FALLS 86,555 109,300 79% 109,300 79%
SUN VALLEY 20,247 24,750 82% 24,750 82%
CANYON COUNTY 104,221 139,000 75% 139,000 75%
STATE STREET 76,853 82,000 94% 82,000 94%
CENTRALADA 74,489 87,000 86% 87,000 86%
ALL OTHER 280,541
--j Year 3(Dth)
Planned Capacity Existing+ %of Existing+
Area of Interest Total Peak Day Existing Capacity %of Capacity Upgrade Upgrade Capacity Upgrade Capacity
IDAHO FALLS 88,310 109,300 81% 109,300 81%
SUN VALLEY 20,497 24,750 83% 24,750 83%
CANYON COUNTY 107,241 139,000 77% - 139,000 77%
STATE STREET 78,362 82,000 965/8 13,000 95,000 82%
CENTRAL ADA 75,984 87,000 87% - 87,000 87%
ALL OTHER 283,670
269

2028 Year 4(Dth)
Planned Capacity Existing+ %of Existing+
Area of Interest Total Peak Day Existing Capacity %of Capacity Upgrade Upgrade Capacity Upgrade Capacity DRAFT
IDAHO FALLS 89,942 109,300 82% 109,300 82%
SUN VALLEY 20,740 24,750 84% 24,750 84%
CANYON COUNTY 110,237 139,000 79% 139,000 79% MODEL
STATE STREET 79,870 95,000 84% 95,000 84%
CENTRAL ADA 77,478 87,000 89% 87,000 89%
ALL OTHER 287,240
2029 Year (Dth)- RESULTS
Planned Capacity Existing+ %of Existing+
Area of Interest Total Peak Day Existing Capacity %of Capacity Upgrade Upgrade Capacity Upgrade Capacity LATERALS
IDAHO FALLS 91,611 109,300 84% 109,300 84%
SUN VALLEY 20,984 24,750 95% 24,750 95%
CANYON COUNTY 113,068 139,000 81% 139,000 81%
STATE STREET 81,379 95,000 86% 95,000 86%
CENTRAL ADA 78,974 87,000 91% 87,000 91%
ALL OTHER 291,026
2030 Year 6(Dth)
Planned Capacity Existing+ %of Existing+
Area of Interest Total Peak Day Existing Capacity %of Capacity Upgrade Upgrade Capacity Upgrade Capacity
IDAHO FALLS 93,230 109,300 85% 2,900 112,200 83%
SUN VALLEY 21,224 24,750 86% - 24,750 86%
CANYON COUNTY 115,926 139,000 83% 139,000 83%
STATE STREET 82,892 95,000 87% 95,000 87%
CENTRAL ADA 80,473 87,000 92% 87,000 92%
ALL OTHER 294,269
270

DRAFT MODEL RESULT GENERAL SUPPLY BALANCE
SUMMARY
SLIP l; hrej. 10/1/2025 11/1/2025 12/1/2025 111/2026 2/1/2026 3/1/2026 4/1/2026 5/1/2026 6/1/2026 7/1/2026 8/1/2026 9/1/2026
AECO 5.020.377 6.065.968 7.147.872 7,147.872 6,456,143 6.761.047 3.341.270 2.457,540 1.285.824 1.096.245 1.299.113 2.957.778
Rockies 306.475 331.189 498.059 615.107 375.951 432.228 1.195.720 2.297,534 631.189 218.811 250.288 631.189
Sumas - - - 450 - 92.605 300.000 2,335,719 300.000 - - -
All Other 2,737 2.649 2.737 2,737 2,472 2.737 2.649 2,737 2.649 2.737 2.737 2,649
Canyon Count' 2.031 1.965 2.031 2,031 1.834 2.031 1.965 2.031 1,965 2.031 2.031 1,965
Central Ada 2,373 2.296 2,373 2,373 2.143 2.373 2.296 2,373 2.296 2.373 2,373 2,296
Idaho Falls 1,541 1.491 1.541 1,541 1,392 1.541 1.491 1.541 1,491 1.541 1,541 1,491
State Street 2,345 2.270 2.345 2,345 2.118 2.345 2.270 2.345 2.270 2.345 2.345 2,270
Sun Valley 232 224 232 232 209 232 224 232 224 232 232 224
Storage - 7,541 2,110,606 1 4,702.679 1,848,802 123.489 - - - - - -
271

DRAFT MODEL RESULT GENERAL SUPPLY BALANCE
SUMMARY
Supply Area 10/1/2030 11/1/2030 12/1/2030 1/1/2031 2/i/2031 3/1/2031 4/1/2031 5/1/2031 6/1/2031 7/1/2031 8/1/2031 9/1/2031
AECO 4,881,307 5,331,070 6,792,507 7,147,872 6,456,143 6,331,960 3,624,443 1,614,240 1,313,353 1,117,970 1,341,912 2,110,613
Rockies 1,352,297 1,337,862 1,386,590 1,535,949 1,252,404 1,464,858 1,641,862 1,386,590 1,341,862 1,263,051 1,294,619 1,341,862
Sumas 108,590 105,087 108,590 108,590 98,081 108,590 405,087 418,590 405,087 418,590 418,590 405,087
All Other 14,112 13,657 14,112 14,112 12,746 14,112 13,657 14,112 13,657 14,112 14,112 13,657
Canyon County 8,750 8,468 8,750 8,750 7,903 8,750 8,468 8,750 8,468 8,750 8,750 8,468
Central Ada 12,236 11,841 12,236 12,236 11,052 12,236 11,841 12,236 11,841 12,236 12,236 11,841
Idaho Falls 12,328 11,930 12,328 12,328 11,135 12,328 11,930 12,328 11,930 12,328 12,328 11,930
State Street 12,094 11,704 12,094 12,094 10,923 12,094 11,704 12,094 11,704 12,094 12,094 11,704
Sun Valley 2,682 2,595 2,682 2,682 2,422 2,682 2,595 2,682 2,595 2,682 2,682 2,595
Storage - 135,684 2.270,407 4,714.616 1,582,433 89,975 - - - - - -
272

DRAFT MODEL RESULT GENERAL SUPPLY BALANCE
SUMMARY
Peak Day Supply
700,000
600,000
500,000
E 400,000
a�
Ca
w 300,000
0
200,000
100,000
2025 2026 2027 2028 2029 2030
AECO Rockies Sumas Storage DSM -Demand -Demand less DSM
273

M
CAPACITY RESOURCES
Northwest Daily Maximum Transportation Capacity (MMBtu)
• Intermountain has segmented
capacity from Sumas to IGC at
2025 2026 2027 2028 2029 2030 Stanfield. Intermountain owns
Stanfield 224,565 224,565 224,565 224,565 224,565 224,565 Stanfield to IGC.
Rockies 59,328 59,328 59,328 59,328 59,328 59,328 0Intermountain recently added
Citygate 10,000 10,000 10,000 10,000 10,000 10,000 Stanfield Capacity via the GTN
Total Capacity 293,893 293,893 293,893 293,893 293,893 293,893 X p re s s project.
• Intermountain is actively
Storage Withdrawals with Bundled Capacity 155,175 155,175 155,175 155,175 155,175 155,175 participating in a Rockies
JP TF-2 Capacity 30,337 30,337 30,337 30,337 30,337 30,337 expansion to meet peak day
Nampa and Rexburg 55,500 55,500 55,500 55,500 55,500 55,500 s h o rtfa I I s.
Maximum Deliverability 534,905 534,905 534,905 534,905 534,905 534,905 on-System Storage is 55,000
dth/day.
274

Employs Utility Standard Practice Method To Optimize System
Models DSM & Storage
Handles storage withdrawal and injection across seasons
Provides a check on need for lateral expansion.
Provides a check on transport and supply capacity
275

QUESTIONS ?

FEEDBACK
MISSIONS
■
■ [e-mail]
■ Please provide comments and feedback within 10 days
277

IGRAC #3
INTERMOUNTAIN""
GAS COMPANY
A Subsidiary of MDU Resources Group,Inc.
RESOURCEINTEGRATED
INTERMOUNTAINAUGUST 13.2025
.URCE ADVISORY COMMITTEE
Date &time: 9/17/2025, 9:00 AM to 11:00 PM MT
Location: Microsoft Teams Meeting
Presenters: Ryan Denton, Kathleen Campbell, Zachary Sowards, Brian Robertson
In attendance: Bailey Steeves, Brian Robertson, Bruce Folsom, Chris Robbins, Darcy Neigum,
Eric Wood, Jenny De Boer, Kathleen Campbell, Kimberly Loskot, Kristen
Nieskens, Mark Sellers-Vaughn, Matt Hunter, Michael Parvinen, Rebecca
Wildman, Russ Nishikawa, Ryan Denton, Seungjae Lee, Vicki Stephens,
Zachary Sowards
Introduction
Brian Robertson, Manager of Supply Resource Planning, opened the meeting by welcoming and thanking
stakeholders for participating in Intermountain's IRP Process. Brian then proceeded with introductions,
the agenda, a safety moment, and a reminder of the stakeholder engagement goals.
Presentation #1 —Load Demand Curves (Ryan Denton)
• Ryan shared the key variables, and the methodology of how the load demand curves are
calculated.
• Ryan described the reasons why load demand curves are important; mainly understanding
capacity needs and storage management.
• Ryan then shared the load demand curves first and final year of the planning horizon, describing
the growth and any potential shortfalls for Intermountain's total system as well as each area of
interest(AOI).
Question: "What kind of sensitivity modeling is there around key variables"
Answer: Brian stated that Intermountain does a high and low growth as well as sensitivity
modeling around 4 demand side management scenarios.
Presentation #2— Distribution System Enhancements (Kathleen Campbell and Zachary Sowards)
• Kathleen and Zachary provided project needs for each AOI, describing timing, costs, and capacity
gained for each project;
o In 2027, Intermountain anticipates a Caldwell reinforcement and a New Plymouth gate
upgrade to ensure 2030 growth projections are met.
Page 1 of 2
278

o Canyon County, Central Ada, and Sun Valley showed no reinforcement needs as the
recent upgrades from previous IRPs meet 2030 growth expectations.
o State Street and Idaho Falls AOIs anticipate upgrades to meet 2030 growth expectations.
Question: "Is there a target year for designing the distribution line?"
Answer: Kathleen responded that there are multiple factors that go into distribution system
projects. There are limitations to which projects can be done but the target is to
ensure there is enough capacity in the five year IRP planning horizon. It also
depends on the type of project, for example, a compressor generally wants to be
built to serve for ten to twenty years of growth.
Presentation#3—IRP Optimization Model (Brian Robertson)
• Brian described the IRP Optimization Model (Plexos) and how it integrates all the elements of an
IRP such as load demand curves, supply, transport, storage, demand side management, and
distribution system modeling.
o Transportation includes the maximum daily quantity, reservation charge, flow
charge, and a fuel loss percentage rate.
o As for storage, Intermountain has 30,377 dth per day from JP, 155,175 dth per
day from Plymouth, and 70,144 dth per day from Clay Basin for a total of
approximately 255,626 dth per day of off-system storage. Intermountain can also
withdrawal 50,000 dth per day from Nampa and 5,500 dth per day from Rexburg.
o Brian described how supply was modeled in a way that emulates real world
supply purchasing.
o Load Demand Curves are loaded into Plexos into demand areas.
• Brian reshared draft model results of the capacity shortfalls at each AOI and summarized recent
and future upgrades.
• High level information on upstream transportation shortfall solutions was discussed.
• Brian then shared supply and storage annual and peak day preliminary results.
Question: "How does capacity needs of other states impact Intermountain?"
Answer: Brian stated that Intermountain has firm capacity rights on upstream pipelines,
which means the pipelines are obligated to provide Intermountain that service.
The Meeting was Adjourned—Intermountain is focusing on the IRP narrative and aims to have
a draft circulated by the end of October
Page 2 of 2
279

ltlmrER
AI:DLI
0
4T)
liq
GAS COMPANY
A Subsidiary of MDU Resources Group, Inc.
INTEGRATED RESOURCE PLAN
DECEMBER 3, 2025
INTERMOUNTAIN GAS RESOURCE ADVISORY COMMITTEE (IGRAC)

•
m I
■ Introductions
■ Feedback Process
■ Agenda

FEEDBACK
MISSIONS
■
■ [e-mail]
■ Please provide comments and feedback within 10 days
282

1 . 1
Welcome & Introductions — Brian Robertson (Manager, Supply Resource Planning)
Safety Moment — Brian Robertson (Manager, Supply Resource Planning)
Upstream Capacity Needs — Brian Robertson (Manager, Supply Resource Planning)
Questions/Discussion
283

BRIAN ROBERTSON
MANAGER, SUPPLY RESOURCE PLANNING

Be Ready _Winter Weather.
If power lines fall on
Install a smoke detector Have your chimney 1W our car,warn people
and carbon monoxide or flue inspected , ,r lines s,
or power lines.
IJ po►t e
not to touch the car
detector in your home. every year. are down, Calf
Make sure the ►'our local utility
batteries are nd emergency
Weathei proof working! smices
your hone to
protect against
the cold.
Insulate walls
and attic.
Chec-A our more
ripe on winter Caulk and weather-strip
weather indoor doors and windows.
Never leave lit candles or
other flames unattended. '',�. i Alake sure your Car 1S read{'
Bring your pets indoors for winter Ira ref.
as temperatures drop!
Prepare yourself Dress warmly and limit Check antifreeze level
for exposure to exposure to the cold to and have radiator
iK inter weather.
prevent frostbite. system serviced.
Avoid getting wet to Replace worn tires and
prevent hypothermia. Make a winter check tire air pressure.
285 emergency kit to
Wh'w.Cdc.gov1phpr/infographies.htm keep in your car. Keep gas tank full to avoid
ice in tank and fuel lines.

BRIAN ROBERTSON
MANAGER SUPPLY RESOURCE PLANNING

2025 Load Demand Curve
Design Base Case
Total Company
700,000 -
600 000 Peak Day 536,800 Dth
- - - - - - - - - - - - - - - -
500,000
400,000
s
0
300,000
200,000
100,000
10/1/2025 11/1/2025 12/1/2025 1/1/2026 2/1/2026 3/1/2026 4/1/2026 5/1/2026 6/1/2026 7/1/2026 8/1/2026 9/1/2026
Core+LV-1 Demand less DSM — — Maximum Transport Deliverabiitywith LNG — — Maximum Transport Deliverability
287

2030 Load Demand Curve
Design Base Case
Total Company
700,000
600000 Peak Day 582,518 Dth
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
500,000
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
400,0()0
L
300,000
200,000
I
100,000
10/1/2030 11/1/2030 12/1/2030 1/1/2031 2/1/2031 3/1/2031 4/1/2031 5/1/2031 6/1/2031 7/1/2031 8/1/2031 9/1/2031
Core+LV-1 Demand less DSM — — Maximum Transport Deliverability with LNG — — Maximum Transport Deliverability
288

RESOURCE CAPABILITIES
(VOLUMES IN DTHS/D)
2025 2026 2027 2028 2029 2030 2031
Stanfield 2241,565 224,565 2241565 224,565 224,565 224,565 224,565
Rockies 59,328 59,328 59,328 59,328 59,328 59,328 59,328
Citygate 10,000 10,000 10,000 10,000 10,000 10,000 10,000
Total Capacity 293,893 293,893 293,893 293,893 293,893 293,893 293,893
Storage Withdrawals with
Bundled Capacity 155,175 155,175 155,175 155,175 155,175 155,175 155,175
P TF-2 Capacity 30,337 30,337 30,337 30,337 30,337 30,337 30,337
Nampa and Rexburg 55,500 1 55,500 55,500 55,500 1 55,500 1 55,500 55,500
Maximum Deliverability 534,905 534,905 534,905 534,905 534,905 534,905 534,905
289

Peak Day Load (Dths) Compared to Current Maximum Deliverability of Resources
70 0,00 0
60 0,00 0
50 0,00 0
40 0,00 0
30 0,00 0
200,000
100,000
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041
O Peak Day Low Peak Day Base � Peak Day High Maximum Deliverability
290

OPTIONS AND ALTERNATIVES
■ Upstream options
• Supply
■ Storage
■ Transportation
■ Downstream options
■ LNG
■ DSM
■ Electrification
■ Others?
291

REVIEW OF ROCKIES COLUMBIA CONNECTOR PROJECT
Rockies Columbia Connector (Proposed)
Project Over_vie-w:
• Integrated expansion of NWP mainline to
WMAarris. provide firm incremental transportation from
�� the Rockies Opal area and Stanfield, OR with
delivers to Idaho and points along the 1-5
o....� corridor
AOCKIES
N,•�a+.Mon COLI 14GL1 CONNECTOR
am-d
LEGEND Project Benefits:
j ...�. - mow•-- - Supports growth in region
,,,,,•..,�,,,,,,,,,, Access to Rockies supply
'FAMPULD • �•^� Executable - Brownfield project - No
showstoppers
•��••� Enhances energy resiliency and reliability
during peak demand periods
„�„ ��......«... Addresses a •-300 MMcf/d supply shortfall due
— to Woodfibre LNG in 2027
Es
Esimated CO2 emissions reductions up to
s 43,000 tons/year from NWP operations
D.wL
Project Status:
Non-Binding Open Season closed August 6,
` 2025 (Open Season offered up to 650 MMcf/d)
• Negotiating Precedent Agreements - Q4 2025
Finalizing scope based on Open Season /
commitments
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LNG PEAK-SHAVING
11 FACILITIES
FilingFacility IRP / Planning Regulatory Reported Storage
Link ProjectCost Capacity
Puget Sound WA UTC docket _$489 million
Energy (WA) Tacoma LNG PSE Gas IRP UG-230393 capital cost (end —9.6 million dth
of 2022)
Pacific Lelu Island LNG BC EAO, CEAA Planned $ 1 1 .4- 18 — 18-20M Dth
Northwest LNG Export Project NA (Petronas) 2012 billion investment annually
(BC, canceled)
NW Natural Peak-shaving OPUC docket Capacity in
(OR/WA) LNG NW Natural IRP UG 456 undisclosed PHMSA/permit
filings
FortisBC (BC) Tilbury LNG BCUC Tilbury BCUC Order —$ 1 . 14 billion —25.4 million dth
LNG CPCN G-62-23
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■ PSE Tacoma LNG: december 12023.pdf, PSE LNG HIS Cover Pages.pdf
■ Lelu Island LNG: Pacific NorthWest LNG Project, British Columbia - Offshore Technology
■ Northwest Natural: Ic79has 155146.pdf
■ FortisBC Tilbury LNG: BCUC Approves FortisBC's Tilbury Liquefied Natural Gas
294

ESTIMATED RATE • RESIDENTIAL CUSTOMERS
The table below reflects the estimated rate impact in 2030 to residential customers based on
Rockies Columbia Connector capacity acquired. It's important to keep in mind by the time you get
out to 2030, the impact of the expansion will be less because of customer growth will increase the
billing determinants.
10090001
Estimated Annual Revenue Impact of $60,225,000
RCC Reservation Charge
Percentage Increase 20.8%
295

QUESTIONS ?

FEEDBACK
MISSIONS
■
■ [e-mail]
■ Please provide comments and feedback within 10 days
297

IGRAC #4
INTERMOUNTAINO
GAS COMPANY
A Subsidiary of MDU Resources Group,Inc.
Date &time: 12/3/2025, 9:00 AM to 9:35 PM MT
Location: Microsoft Teams Meeting
Presenters: Brian Robertson
In attendance: Bailey Steeves, Brian Robertson, Bruce Folsom, Chris Robbins, Eric Wood,
Jenny De Boer, Kathleen Campbell, Kristen Nieskens, Michael Brutocao, Michael
Parvinen, Ryan Denton, Seungjae Lee, Vicki Stephens, Zachary Sowards
Introduction
Brian Robertson, Manager of Supply Resource Planning, opened the meeting by welcoming and thanking
stakeholders for participating in Intermountain's IRP Process. Brian then proceeded with introductions,
the agenda, a safety moment, and a reminder of the stakeholder engagement goals.
Presentation #1 —Upstream Capacity Needs (Brian Robertson)
• Brian shared charts on Intermountain's current usage under a peak event compared to the
Company's current capacity to serve customers. He also shared the maximum capacity
compared to the low, base, and high growth forecasts. This showed a need for more capacity to
meet customers' needs under a peak event.
• Brian described the options to meet this capacity need, sharing that the two most viable options
are upstream transportation and LNG.
• Brian shared the Rockies Connector Expansion and the benefits of this type of project.
• Brian shared regional LNG projects, showing the costs of these projects, and describing the
benefits of an LNG project.
• Ultimately, Intermountain plans to move forward with the Rockies Connector Expansion while
continuing to investigate LNG for future consideration in the case Idaho growth continues to
expand.
• Brian then shared estimated impacts to customer rates for this type of project.
The Meeting was Adjourned—Intermountain is focusing on the IRP narrative and aims to have
a final filed by the week of December 15.
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