200405062004 IRP.pdf

Intermountain Gas Company
2005-2009 Integrated Resource Plan

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Table of Contents

Executive Summary........................................................................................................ 1

Residential and Commercial Customer Growth Forecast............................................... 9

Industrial Forecast .......................................................................................................... 22

Usage Per Customer Under Design Degree Days ......................................................... 28

Design Heating Degree Days ......................................................................................... 31

Traditional Supply Side Resources................................................................................. 36

Non-Traditional Resources............................................................................................. 49

Distribution System Modeling ......................................................................................... 51

Promoting The Efficient Use of Natural Gas................................................................... 53

Resource Optimization ................................................................................................... 57

Intermountain Gas Company
2005 - 2009 Integrated Resource Plan

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Table of Exhibits

Exhibit No. 1 Appendix A John Church Economic Forecast
Appendix B IGC Penetration Rates
Appendix C IGC Conversion Rates
Appendix D Base Case - New Customers, Adjustments and Total Customers
Appendix E High Growth - New Customers, Adjustments & Total Customers
Appendix F Low Growth - New Customers, Adjustments & Total Customers

Exhibit No. 2 Appendix A Regression Equations & Statistics
Appendix B Regression Equation - Examples
Appendix C Regression Data - Therms, Binary and Degree Days

Exhibit No. 3 Appendix A Design - Base Case Load Duration Curve Data
Appendix A.1 Total Company - Annual Summary Data
Appendix A.2 Total Company - Load Duration Curve Charts
Appendix A.3 Total Company - Daily Detail Data
Appendix A.4 Idaho Falls - Annual Summary Data
Appendix A.5 Idaho Falls - Load Duration Curve Charts
Appendix A.6 Idaho Falls - Daily Detail Sheet
Appendix A.7 Sun Valley - Annual Summary Data
Appendix A.8 Sun Valley - Load Duration Curve Charts
Appendix A.9 Sun Valley - Daily Detail Data
Appendix A.10 Canyon County - Annual Summary Data
Appendix A.11 Canyon County - Load Duration Curve Charts
Appendix A.12 Canyon County - Daily Detail Data

Appendix B Design - High Growth Load Duration Curve Data
Appendix B.1 Total Company - Annual Summary Data
Appendix B.2 Total Company - Load Duration Curve Charts
Appendix B.3 Total Company - Daily Detail Data
Appendix B.4 Idaho Falls - Annual Summary Data
Appendix B.5 Idaho Falls - Load Duration Curve Charts
Appendix B.6 Idaho Falls - Daily Detail Data
Appendix B.7 Sun Valley - Annual Summary Data
Appendix B.8 Sun Valley - Load Duration Curve Charts
Appendix B.9 Sun Valley - Daily Detail Data
Appendix B.10 Canyon County - Annual Summary Data
Appendix B.11 Canyon County - Load Duration Curve Charts
Appendix B.12 Canyon County - Daily Detail Data

Intermountain Gas Company
2005 - 2009 Integrated Resource Plan

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Exhibit No. 3 (Continued)

Appendix C Design - Low Growth Load Duration Curve Data
Appendix C.1 Total Company - Annual Summary Data
Appendix C.2 Total Company - Load Duration Curve Charts
Appendix C.3 Total Company - Daily Detail Data
Appendix C.4 Idaho Falls - Annual Summary Data
Appendix C.5 Idaho Falls - Load Duration Curve Charts
Appendix C.6 Idaho Falls - Daily Detail Data
Appendix C.7 Sun Valley - Annual Summary Data
Appendix C.8 Sun Valley - Load Duration Curve Charts
Appendix C.9 Sun Valley - Daily Detail Data
Appendix C.10 Canyon County - Annual Summary Data
Appendix C.11 Canyon County - Load Duration Curve Charts
Appendix C.12 Canyon County - Daily Detail Data

Exhibit No. 4 Appendix A Map of Pipelines and Supply Basins
Table 4.1 Congressional Acts and FERC Orders
Chart 4.1 Historical Spot Prices

Exhibit No. 5 Diagram 5.1 Arc and Node Representation
Diagram 5.2 Arc and Node Definition
Table 5.1 Aggregation of Calendar Days into Model Periods
Table 5.2 Projected Natural Gas Prices by Basin
Table 5.3 Pricing for Supply Inputs
Appendix A Model Inputs - Demand
Appendix B Model Inputs - Supply
Appendix C Model Inputs - Transportation
Appendix D Model Results - Base Case
Appendix E Model Results - High Growth
Appendix F Model Results - Low Growth
Appendix G Public Workshop Announcement

Exhibit No. 6 DVD: Conservation Hints and Tips

Intermountain Gas Company
2005 - 2009 Integrated Resource Plan

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Intermountain Gas Company
Integrated Resource Plan
Executive Summary

Natural gas continues to be the fuel of choice in Idaho. Southern Idaho's manufacturing plants, commercial
businesses, new homes and anticipated new electric power plants, all rely on natural gas to provide an
economic, efficient, environmentally friendly and most comfortable form of heating energy. Intermountain
Gas Company endorses and encourages the wise and efficient use of energy in general and, in particular,
natural gas for high efficient uses in Idaho and Intermountain's service area (see Pages 49-52). Forecasting
the demand of Intermountain's growing customer base is a regular part of Intermountain's operations, as is
determining how to best meet the load requirements brought on by this demand. Public input is an integral
part of this planning process. The customer demand forecast and resource decision making process is
ongoing. This Integrated Resource Plan document represents a snapshot in time similar to a balance sheet.
It is not meant to be a prescription for all future energy resource decisions, as conditions will change over the
planning horizon impacting areas covered by this Plan. Rather, this document is meant to describe the
currently anticipated conditions over the five-year planning horizon, the anticipated resource selections and
the process for making those resource decisions. The planning process described herein is an integral part
of Intermountain's ongoing commitment to make the wise and efficient use of natural gas an important part of
Idaho's energy future.

Backdrop

Intermountain Gas Company ("Intermountain") is the sole distributor of natural gas in Southern Idaho. Its
service area extends across the entire breadth of Southern Idaho, an area of 50,000 square miles, with a
population of approximately 1,000,000. During fiscal year 2003, Intermountain served an average of 242,000
customers in 74 communities through a system of approximately 9,500 miles of transmission, distribution
and service lines. Over 351 miles of transmission, distribution and service lines were added during fiscal
2003 to accommodate new customer additions and maintain service for Intermountain’s growing customer
base.

The economy of Intermountain’s service area is based primarily on agriculture and related industries. Major
crops are potatoes and sugar beets. Major agriculture-related industries include food processing and
production of phosphate minerals. Other significant industries are electronics, general manufacturing,
services and tourism.

Intermountain provides natural gas sales and services to two major markets: the residential/commercial
market and the industrial market. During the first quarter of fiscal year 2004, an average of 224,000
residential and 25,000 commercial customers used natural gas primarily for space and water heating,
compared to an average of 213,000 residential and 25,000 commercial customers in the first quarter fiscal
year 2003. This equates to an increase in average residential and commercial customers of 5%.

Intermountain’s industrial customers transport natural gas through Intermountain’s system to be used for
boiler and manufacturing applications, as well as feedstock in the production of chemical fertilizers. Industrial
demand for natural gas is strongly influenced by the agricultural economy and the price of alternative fuels.
Forty-Eight percent (48%) of the throughput on Intermountain’s system during fiscal 2003 was attributable to
industrial sales and transportation.

Intermountain Gas Company
2005 - 2009 Integrated Resource Plan

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Intermountain's peak day loads (throughput during the projected coldest winter day) are growing at a
manageable rate. The growth in Intermountain’s projected peak day load is attributable to two factors: 1)
growth in Intermountain’s customer base, primarily residential and commercial, and 2) production related
growth occurring in Intermountain’s industrial firm transportation market which impacts Intermountain’s
distribution system while not impacting the need for additional interstate pipeline capacity (See Firm Contract
Demand, Page 25).

The customer growth forecast1 was analyzed and forecast not only from a total company perspective but also
by specific geographic regions within Intermountain’s service territory. The regions were selected based upon
the anticipated or known need for system upgrades within each specific region. The regions, as more fully
delineated later in this document, consist of The Idaho Falls Lateral Region, The Sun Valley Lateral Region,
The Canyon County Region and the “All Other” Region.

Peak day sendout studies and load duration curves were developed under design weather conditions (see
page 31) to determine the magnitude and timing of future deficiencies in firm peak day delivery capability
from both a total company interstate mainline perspective, as well as within each specific geographic region.
Residential, commercial and industrial customer peak day sendout was matched against available resources
to determine which combination of new resources would be needed to meet Intermountain’s future peak day
delivery requirements at the best possible cost.

Forecast Peak Day Sendout
Total Company

Residential, commercial and industrial peak day load growth on Intermountain’s system under design
conditions is forecast over the five-year period to grow at an average annual rate of 4%. The table below
summarizes the forecast for peak day sendout under the “base case” customer growth assumption.

LOAD DURATION CURVE - TOTAL COMPANY DESIGN BASE CASE
(Volumes in Therms)

NWP Firm Peak Day Sendout Incremental Peak Day Sendout
Transport Core Industrial Core Industrial
Capacity Market Firm CD Total Market Firm CD1 Total

FY05 2,403,300 3,499,800 223,890 3,723,690
FY06 2,463,300 3,632,070 223,890 3,855,960 132,270 0 132,270
FY07 2,463,300 3,825,120 223,890 4,049,010 193,050 0 193,050
FY08 2,463,300 3,968,160 223,890 4,192,050 143,040 0 143,040
FY09 2,463,300 4,108,150 223,890 4,332,040 139,990 0 139,990
____________________ 1 Future growth in transport CD is limited to T-4, which does not affect Intermountain's interstate pipeline capacity requirements.

The above table highlights the fact that growth in the peak day is commensurate with the growth projected to
occur in Intermountain’s residential and small commercial customer markets.

Existing Resources:
1 Multiple residential and commercial customer growth scenarios were developed. Each scenario (“base
case”, “high” and “low”) was driven by the potential for varying outcomes of Idaho’s economy (See Pages 9-
21.)
Intermountain Gas Company
2005 - 2009 Integrated Resource Plan

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Intermountain’s existing firm delivery capability on the peak day is made up of the resources shown on the
following page.

PEAK DAY FIRM DELIVERY CAPABILITY
(Volumes in Therms)
FY05 FY06-FY07 FY08-FY09
Maximum Daily Storage Withdrawals:
Nampa LNG 600,000 600,000 600,000
Plymouth LS 720,000 720,000 720,000
Jackson Prairie SGS 150,000 150,000 225,000
Total Storage 1,470,000 1,470,000 1,545,000
Maximum Deliverability (NWP) 2,403,300 2,463,300 2,463,000
Total Peak Day Deliverability 3,873,300 3,933,300 4,008,300

When forecasted peak day sendout is matched against existing resources, a peak day delivery deficit occurs
during January 2007 and increases as depicted on the following table.

FIRM DELIVERY DEFICIT - TOTAL COMPANY DESIGN BASE CASE
(Volumes in Therms)
FY05 FY06 FY07 FY08 FY09
Peak Day Deficit 1 0 0 115,710 183,750 323,740
Total Winter Deficit2 0 0 115,710 197,110 470,990
Days Requiring Additional Resources 0 0 1 2 2
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1Peaking storage increases by 75,000 therms per day in FY05 which reduces the deficit thereafter.
2Equal to the total winter sendout in excess of interstate capacity less total "peaking" storage. Peaking storage does not
require the use of Intermountain's traditional interstate capacity to deliver inventory to the citygate.

Intermountain Gas Company
2005 - 2009 Integrated Resource Plan

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0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
3,500,000
4,000,000
4,500,000
TH
E
R
M
S
FY05 FY06 FY07 FY08 FY09
FIRM PEAK DAY DELIVERIES
Design Base Case
Interstate Capacity Storage Deficit

Because Intermountain’s storage gas has been dispatched or “rationed” around the peak day in order to meet
the higher demand days first, a deficit of firm capacity begins to occur “around” the peak day during the
“shoulder months” under design conditions beginning in the winter of 2007.

Firm transportation capacity will be secured by Intermountain during these projected deficit shoulder periods.
Intermountain, together with its gas procurement agent, is performing an extensive evaluation of the most
advantageous way to eliminate this deficit taking into consideration first of all firm delivery capability to
Intermountain’s core market together with economic efficiency. The projected deficits in firm deliverability will
be eliminated in a timely manner through one or more means including, but not limited to, 1) long-term firm
capacity release and/or segmentation, 2) city gate deliverable gas supply, 3) storage together with related
mainline rights and, 4) call back opportunities.
Regional Studies
As mentioned above, certain geographic regions within Intermountain’s service territory were analyzed based
upon the anticipated or known need for distribution system upgrades within each specific region. Not unlike
the total company interstate mainline perspective, the projected peak day sendout for each region was
measured against the known distribution capacity available to serve that region. In addition to the firm
delivery requirements for Intermountain’s residential and commercial customers, the needs of those industrial
customers contracting for firm distribution only transportation service (Intermountain’s “T-4” customers) were
also included as part of these regional studies. A wide array of alternatives were evaluated in determining
the potential way to best meet the projected deficits in the various regions within Intermountain Gas Company
(see “Non-Traditional Resource Options” - Page 45). Additionally, each region is analyzed within the
framework of the Company’s Distribution System Model (See Page 47).

Idaho Falls Lateral Region
The Idaho Falls Lateral (“IFL”) is 104 miles in length and serves a number of cities between Pocatello in the
south to St. Anthony in the north. The customers served off the IFL represent a diverse base of residential,
commercial and large industrial customers. The residential, commercial and industrial load served off the IFL
represents approximately 16% of the total company customers and 20% of the company’s total winter
sendout during the winter of 2003-2004.

Intermountain Gas Company
2005 - 2009 Integrated Resource Plan

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When forecasted peak day sendout on the IFL is matched against the existing peak day distribution capacity
(690,000 therms), a peak day delivery deficit occurs during 2005 and increases at levels shown on the
following tables:

LOAD DURATON CURVE - IDAHO FALLS DESIGN BASE CASE
(Volumes in Therms)

Existing
Distribution Peak Day Sendout Incremental Peak Day Sendout
Transport Core Industrial Core Industrial
Capacity Market Firm CD1 Total Market Firm CD2 Total

FY05 690,000 546,650 243,040 789,690
FY06 690,000 566,380 243,040 809,420 19,730 0 19,730
FY07 690,000 594,240 243,040 837,280 27,860 0 27,860
FY08 690,000 614,680 243,040 857,720 20,440 0 20,440
FY09 690,000 636,460 243,040 879,500 21,780 0 21,780
______________________________ 1Existing firm contract demand includes T-1, T-2 and T-4 , and Idaho Falls Compressors Station requirements. 2Future growth in transport CD is limited to T-4 which only impacts Intermountain's distribution capacity requirements.

FIRM DELIVERY DEFICIT - IDAHO FALLS DESIGN BASE CASE
(Volumes in Therms)

FY05 FY06 FY07 FY08 FY09

Peak Day Deficit 99,690 119,420 147,280 167,720 189,500

Total Winter Deficit1 240,720 313,900 395,940 479,210 565,670

Days Requiring Additional Capacity 4 4 4 4 6
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1Equal to the total winter sendout in excess of distribution capacity.

The industrial customer base on the IFL is unique in that several of these customers have the potential and
ability to mitigate peak day consumption by switching to fuel oil during extreme cold temperatures. Although
these customers prefer using natural gas to any other fuel alternative, Intermountain believes that small, short
duration peak day distribution delivery deficits in the future can be eliminated or at least mitigated by working
with these customers to facilitate the use of fuel oil at these customer’s facilities. However, the projected
delivery deficits are of such magnitude that “looping” of the existing system is warranted adding the
necessary firm delivery capability to that area.

Sun Valley Lateral Region
The residential, commercial and industrial load served off the Sun Valley Lateral (“SVL”) represents
approximately 4% of the total company customers and 4% of the company’s total winter sendout during the
winter of 2003-2004.
When forecasted peak day sendout on the Sun Valley Lateral ("SVL") is matched against the existing peak
day distribution capacity (144,000 therms), a peak day delivery deficit occurs during 2005 and increases at
the levels shown on the following tables:
Intermountain Gas Company
2005 - 2009 Integrated Resource Plan

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LOAD DURATON CURVE - SUN VALLEY DESIGN BASE CASE
(Volumes in Therms)

Existing
Distribution Peak Day Sendout Incremental Peak Day Sendout
Transport Core Industrial Core Industrial
Capacity Market Firm CD1 Total Market Firm CD2 Total

FY05 144,000 137,980 8,150 146,130
FY06 144,000 141,780 8,150 149,930 3,800 0 3,800
FY07 144,000 147,750 8,150 155,900 5,970 0 5,970
FY08 144,000 151,840 8,150 159,990 4,090 0 4,090
FY09 144,000 156,350 8,150 164,500 4,510 0 4,510
______________________________ 1Existing firm contract demand includes T-1, T-2 and T-4 requirements. 2Future growth in transport CD is limited to T-4 which only impacts Intermountain's distribution capacity requirements.

FIRM DELIVERY DEFICIT - SUN VALLEY DESIGN BASE CASE
(Volumes in Therms)

FY05 FY06 FY07 FY08 FY09

Peak Day Deficit 2,130 5,930 11,900 15,990 20,500

Total Winter Deficit1 2,130 7,590 17,450 25,450 34,280

Days Requiring Additional Capacity 1 2 2 2 2
_______________________________
1Equal to the total winter sendout in excess of distribution capacity.

As can be seen from the above table, growth along the SVL warrants an upgrade to the existing pipeline
system. The tourism industry driven industrial load on the SVL is limited in size and does not currently have
the capability to switch to alternative fuels as a means of mitigating peak day sendout. Again, a wide array of
alternatives were evaluated in determining the potential ways to best meet the projected deficits.
Intermountain plans to increase the delivery capability and ultimate capacity on the SVL through a series of
cost effective system upgrades to be performed over the next several years.

Canyon County Region
The residential, commercial and industrial load served off the Canyon County Lateral (“CCL”) represented
approximately 14% of the total company customers and 17% of the company’s total winter sendout during the
winter of 2003-2004.
When forecasted peak day sendout on the Canyon County Lateral CCL is matched against the existing peak
day distribution capacity (595,000 therms), a peak day delivery deficit occurs during 2006 and increases at
the levels shown on the following tables:
Intermountain Gas Company
2005 - 2009 Integrated Resource Plan

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LOAD DURATON CURVE - CANYON COUNTY DESIGN BASE CASE
(Volumes in Therms)
Existing
Distribution Peak Day Sendout Incremental Peak Day Sendout
Transport Core Industrial Core Industrial
Capacity Market Firm CD1 Total Market Firm CD2 Total

FY05 595,000 495,720 94,140 589,860
FY06 595,000 518,510 94,140 612,650 22,790 0 22,790
FY07 595,000 550,540 94,140 644,680 32,030 0 32,030
FY08 595,000 572,580 94,140 666,720 22,040 0 22,040
FY09 595,000 589,840 94,140 683,980 17,260 0 17,260
______________________________ 1Existing firm contract demand includes T-1, T-2 and T-4 requirements. 2Future growth in transport CD is limited to T-4 which only impacts Intermountain's distribution capacity requirements.

FIRM DELIVERY DEFICIT - CANYON COUNTY DESIGN BASE CASE
(Volumes in Therms)

FY05 FY06 FY07 FY08 FY09

Peak Day Deficit 0 17,650 49,680 71,720 88,980

Total Winter Deficit1 0 19,730 75,740 122,910 164,190

Days Requiring Additional Capacity 0 2 2 3 4
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1Equal to the total winter sendout in excess of distribution capacity.

While diverse in nature, the industrial customer base served by CCL does not currently have the capability to
switch to alternative fuels as a means of mitigating peak day sendout and Intermountain is currently exploring
optional means of enhancing the distribution capability on this Lateral.

Summary
Residential, commercial and industrial customer growth and its consequent impact on Intermountain’s
distribution system was analyzed using design weather conditions under various projected outcomes of
Idaho’s economy. Peak day sendout under each of these customer growth scenarios were measured against
the available natural gas delivery systems to project the magnitude and timing of delivery deficits, both from a
total company perspective as well as a regional perspective. The resources brought to bear to meet these
projected deficits were analyzed within a framework of options, both traditional and non-traditional, to help
determine the most cost-effective means available to manage these deficits. In utilizing these various options,
Intermountain’s core market and firm transportation customers will continue to rely on uninterrupted firm
service both now and in the years to come.
Intermountain Gas Company
2005 - 2009 Integrated Resource Plan

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Intermountain Gas Company
2005 - 2009 Integrated Resource Plan

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RESIDENTIAL AND COMMERCIAL CUSTOMER GROWTH FORECAST

This section of the Intermountain Gas Company (IGC) Integrated Resource Plan (IRP) describes and
summarizes the residential and commercial customer growth forecast for the years 2005 through 2009. This
forecast provides the anticipated magnitude and direction at IGC’s residential and small customer growth by
IGC Distribution System Segments for IGC’s current service territory. Customer growth is the primary driving
factor in IGC’s five-year demand forecast contained within IGC’s IRP.
The Segments are as follows:
· The Canyon County Segment, which consists of the Core Market Customers in Canyon County.
· The Sun Valley Lateral Segment, consisting of the Core Market Customers in Blaine and Lincoln
Counties.
· The Idaho Falls Lateral Segment, consisting of the Core Market Customers in Bingham, Bonneville,
Fremont, Jefferson, and Madison Counties, along with approximately 25% of the Core Market
Customers in Pocatello, Bannock County.
· The All Other Customers Segment, consisting of the Core Market Customers in Bear Lake, Caribou,
Cassia, Elmore, Gem, Gooding, Jerome, Minidoka, Owyhee, Payette, Power, Twin Falls, and
Washington Counties. Additionally, 75% of the Core Market Customers in Pocatello, Bannock County,
as well as the rest of Bannock County, are included in this segment.
IGC’s customer growth forecast includes three (3) key components:
· Residential New Construction Customers
· Residential Customers who convert to natural gas from an alternative fuel
· Small Commercial Customers
To calculate the number of customers added each year, the annual change in households for each county in
the IGC Service Territory is determined using the Idaho Economics 2003 Economic Forecast for the State of
Idaho by John S. Church (Church Forecast), dated May 2003. Using the assumption that a new household
means a new dwelling is needed, the annual change in households by county is multiplied by IGC’s market
penetration rate in that region to determine the additional residential new construction customers. Next, that
number is multiplied by the IGC conversion rate, which is the anticipated percentage of conversion customers
relative to new construction customers in those locales. This results in the number of expected residential
conversion customers, and when added to the residential new construction numbers, the total expected
additional residential customers across the periods is derived, by county.
The residential new construction numbers by county are multiplied by the IGC commercial rate, which is the
anticipated percentage of commercial customers relative to residential new construction customers in those
locales, to arrive at the number of expected additional small commercial customers.
The residential numbers must be split across our two residential rate classes, RS-1 and RS-2, since these
classes have different load patterns. RS-1 is a customer who does not have both a gas furnace and a gas
water heater, regardless of other appliances. RS-2 customers have at least a gas furnace and a gas water
heater. Virtually 100% of IGC’s residential new construction customers go RS-2, while only regionally varying
percentages of IGC’s residential conversion customers go RS-2. So, the additional residential conversion
customers are split, depending on the region.
Intermountain Gas Company
2005 - 2009 Integrated Resource Plan

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

The following table shows the results from the 5-year customer growth model for each scenario for the total
customers at each year-end, and the annual additional, or incremental, customers:
TOTAL CUSTOMERS ANNUAL ADDITIONAL CUSTOMERS

Low Growth
Base Case
High Growth
Range as a %
Of Base Case
96% - 98%
100% - 100%
100% - 103%
Average as a %
of Base Case
97%
100%
101%
Range as a %
Of Base Case
41% - 99%
100% - 100%
112% - 124%
Average as a %
of Base Case
77%
100%
116%

Low Growth
Base Case
High Growth
Range
(2005 – 2009)
262,852 – 297,913
268,458 – 309,361
269,617 – 317,418

Average
279,975
289,418
293,630
Range
(2005 – 2009)
3,837 – 9,948
9,443 – 10,939
10,602 – 13,089

Average
7,780
10,069
11,681

The following sections explore, more fully, the different components of the customer forecast, including the
Church Forecast, market penetration and conversion rates, and small commercial growth.
Annual Additional Customers
Residential and Small Commercial
2005 - 2009
2,000
4,000
6,000
8,000
10,000
12,000
14,000
FY05 FY06 FY07 FY08 FY09
High Growth
Base Case
Low Growth
Intermountain Gas Company
2005 - 2009 Integrated Resource Plan

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Household Projections / Church Forecast
The May 2003 Church Forecast provides county by county projections of output, employment and wage data
for 21 industry categories for the State of Idaho, as well as a population and household forecast. This
simultaneous equation model uses personal income and employment by industry as the main economic
drivers of the forecast. This model uses forecasts of national inputs and demands for those sectors of the
Idaho economy having a national or international exposure. Industries that do not have as large a national
profile, and are thus serving local communities and demands are considered secondary industries. Local
economic factors, rather than the national economy determine demand for these products.
The Church Forecast uses two methods for population projections: (1) a cohort-component population model
in which annual births and deaths are forecast, and then the net number is either added to or subtracted from
the population, and (2) an econometric model which forecasts population as a function of economic activity.
The two forecasts are then compared and reconciled for each quarter of the forecast. Migration into or out of
the state is arrived at in this reconciliation.
As previously mentioned, the Church Forecast provides three scenarios: (1) base case, (2) high growth, and
(3) low growth. The base case scenario assumes a normal amount of economic fluctuation, a normal
business cycle. This becomes the standard against which changes in customer growth, as affected by the
low and high growth scenarios can be measured.
High and Low Economic Growth Scenarios

The High and Low Growth Scenarios of the 2003 Economic Forecast present alternative views of the
economic future of Idaho and its 44 counties. The High Growth Scenario of the Economic Forecast presents
a long-term vision of rapidly growing economy in Idaho. For example, the High Growth Scenario produces a
projected statewide population of 1,860,000 in the year 2020 versus a Base Case Scenario Idaho population
forecast of 1,699,000 in the same year. This scenario presents an absolute population gain of nearly 549,000
over Idaho’s estimated 2001 population of 1,311,000 and an annual average compound rate of population
growth of 1.9% per year.

Alternatively, the Low Growth Scenario of the 2003 Economic Forecast does not present a rosy economic
outlook for the state of Idaho. In the Low Growth Scenario, Idaho’s 2020 population is projected to reach the
much lower level of 1,607,000. The Low Growth Scenario’s projected 2020 population is 296,000 above
Idaho’s 2001 population – an annual average compound growth rate of 1.1% per year.

While the High and Low Growth Scenarios of the Economic Forecast represent two significantly different
views of Idaho’s economic future, they are not unprecedented. An examination of historic employment,
population, and household growth over the 1970 through 2000 period was performed. This examination,
using either 5-year or 10-year moving averages of the growth of 1-digit SIC code employment concepts,
population, and households in order to dampen the effects of peak periods of economic growth, revealed that
historic levels have in fact exceeded the projected rates of growth in both the High and Low Growth
Scenarios of the 2003 Economic Forecast.

An examination of the possible economic and demographic events that could produce the economic and
population growth projected in the High and Low Growth Scenarios is outlined below.

The High Growth Economic Forecast Scenario:

Since the mid-1980s Idaho’s engine of growth has been the extraordinary growth that it has experienced in
the manufacturing industries. Today Idaho manufacturing firms are in the midst of an economic slowdown as
are many manufacturing industries nationally and internationally. Nevertheless, the current recession has
lessened the long-term attractiveness of manufacturing in Idaho.
Intermountain Gas Company
2005 - 2009 Integrated Resource Plan

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Idaho manufacturing firms express many reasons for the state’s attractiveness to manufacturing industries.
Idaho has a relatively young and educated labor force. Many express that the cost of doing business in Idaho
is lower than in many other areas of the nation. The facets of these lower costs most often cited are: lower
property taxes, lower rates on workman’s compensation and unemployment insurance, a lower level of
government regulation, mandates or restrictions that add costs to doing business, lower land costs, lower
energy costs, and lower labor costs.

A few Idaho manufacturing firms that have operations in other areas of the US have indicated that the lower
labor costs available in Idaho have allowed them to maintain a competitive edge in the world marketplace for
their products. And, indirectly have further cut their labor and training costs and have enhanced labor
productivity. These firms indicate that in order to remain competitive in a worldwide marketplace for their
product they must keep labor costs to a minimum. However, the cost of labor in other parts of the US were
the cost-of-living is high dictates that they must either pay a high wage rate or suffer high rates of labor
turnover, with the adjunctive expense of higher training costs and lower levels of labor productivity. In Idaho
these firms have found that they can compensate their labor with a wage that allows them remain competitive
in the marketplace and provide the worker with a reasonable standard of living. This in turn cuts labor
turnover, training expenses, and increases labor productivity.

However, even in the High Growth Scenario not all of the state’s existing manufacturing firms will grow in the
future. Idaho’s manufacturing industries of Lumber and Wood Products, Food and Kindred Products, and
Chemicals and Allied Products industries are likely to face a long-term decline in activity and employment
levels in almost any scenario.

In addition, two other traditional mainstay Idaho industries, Mining and Agriculture, are likely to face a long-
term future of no-growth or a slow level of decline in both levels of output and employment. The difference
between the economic outlooks for these industries presented in the High and Low Growth Scenarios of the
2003 Economic Forecast is how rapid that rate of decline will be in the future.

Underpinning the High Growth Scenario is a continuation of stellar growth of Idaho’s manufacturing
industries. The pattern of these future manufacturing employment gains are expected to look similar to the
manufacturing growth experienced in Idaho during the 1990s – largely concentrated in the “high-tech”
manufacturing industries of Non-electrical Machinery, Electrical and Electronic Equipment, and Instruments.
Furthermore, these future manufacturing employment gains are likely to be, as they were in the 1990s,
spatially concentrated in the state. Five Idaho counties, Ada, Canyon, Bannock, Bonneville, and Kootenai,
accounted for nearly ninety percent of the state’s overall manufacturing employment gains in the 1990s. With
the exception of Kootenai County, all of the above counties are within the Intermountain Gas Company
service area.

Idaho remains attractive to the high-tech industries. New firms (to Idaho) continue to make inquiries about
locating within the state. While the number of these inquiries slowed as the US economy went into recession,
the current reports are that they have increased significantly after September 11. In addition to the probability
of manufacturing firms locating operations in Idaho, is the continued development of many “spin-off”
manufacturing or service industry firms from the state’s existing manufacturing industries. In the Boise MSA
alone, these “spin-off” establishments have directly created nearly 5,000 jobs locally over the past fifteen
years.

These projected manufacturing employment gains, in turn, spur employment growth in the secondary
industries found in the affected and nearby communities. These secondary industries include employment in
Transportation, Communications, and Utilities; Construction; Wholesale and Retail Trade; Finance, Insurance
and Real Estate; the Service industries; and local serving elements of Government.

In the High Growth Scenario other basic industry sectors of the Idaho economy would contribute to future
employment gains. A renewed interest in nuclear power as a means of generating electricity would bring
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renewed vigor and increased levels of employment to the US Department of Energy’s Idaho Nuclear and
Environmental Laboratory (INEEL). In addition, nuclear waste clean-up activities at INEEL are programmed
to accelerate in the next decade, causing a further upswing in INEEL employment levels. Indirectly, these
would boost secondary industry employment growth in the Eastern Idaho counties of Bannock, Bingham,
Bonneville, Jefferson, and Madison – all within the Intermountain Gas Company service area.

Mountain Home Air Force Base, fifty-five miles southeast of Boise, would experience a modest expansion of
assigned personnel in the High Growth Scenario. The Gowen Field Idaho National Guard facility in Boise
would expand from its current level of nearly 1,000 full-time assigned military personnel to nearly 1,200
assigned personnel in the High Growth Scenario.

Historically, federal government civilian employment in Idaho has been on a path of slow decline for many
years. Federal government employment in the state has always had a very large proportion dedicated to the
management and maintenance of the federal forests and rangelands. These management functions have
been cut to the barest levels over the past two decades. The High Growth Scenario anticipates that federal
employment associated with the management of federal lands will stabilize in the future.

However, the federal employment in Idaho that is primarily serving the local population (the federal courts,
IRS, EPA, OSHA, EDA, FBI, DEA) will increase in the future as Idaho’s population increases. In addition, the
National Fire Center (an inter-agency facility in Boise for the purpose of combating forest and rangeland fires
anywhere in the US) is likely to continue to gain employment in the future.

Many of Idaho’s secondary industries, usually those industries that are deemed to be predominantly local
serving, have a significant proportion of employment that could be classified as basic industry jobs. That is,
they are serving a population or market that is much broader (perhaps international, national, or regional in
scale) than just the local economic area. Some examples include: Washington Group construction, the
corporate headquarters functions of Albertson’s and Boise Cascade, the Sears Regional Credit Center,
Capital One’s Boise Call Center, Hewlett-Packard’s Boise Call Center, or Direct TV. The expansion and
enhancement of Idaho’s telecommunications infrastructure has permitted these firms to locate these
customer service functions in areas far removed from the nations large population centers, such as Boise.

It is estimated that in 2000 there were nearly 7,000 jobs within the Boise MSA associated with these
customer transaction centers, and over ninety percent of those jobs could be classified as basic industry
employment. The High Growth Scenario assumes that this trend will continue in the future. Idaho will capture
a greater number of customer transaction facilities. Most of those new facilities will be located, as they are
today, near the state’s concentration of population and labor force, in Southwest Idaho within the
Intermountain Gas Company service area.

The Low Growth Economic Forecast Scenario:

In the Low Growth Scenario of the 2003 Economic Forecast Idaho’s manufacturing industries do not provide
the stimulus to growth has they have in the past. Today, many of Idaho’s manufacturing firms are suffering
under conditions caused by the current economic slowdown, as are many manufacturing industries nationally
and internationally. However, the Low Growth Scenario of the 2003 Economic Forecast assumes that many
of today’s struggling manufacturing facilities will not survive the current recession.

In the Low Growth Scenario, the long-term employment decline in Idaho’s Lumber and Wood Products
industry accelerates. The state’s Paper and Allied products manufacturing industry takes a serious hit to
employment as its three corrugated cardboard box plants in southern Idaho close – (Boise Cascade -
Nampa, and Longview Fiber plants - Twin Falls and Burley, Idaho).

Changes in US international trade policy causes the removal of the US’s quotas on imported sugar. With the
removal of these protective trade barriers, the US domestic beet sugar industry is not competitive with
imported sugar in the domestic and international marketplace. Idaho is particularly affected by this change in
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policy as the food processing plants involved in producing sugar from sugar beets cease operation in
southern Idaho (at Nampa, Twin Falls, and Paul, Idaho) and eastern Oregon (Nyssa, Oregon). This causes
the loss of nearly 3,500 seasonal and 1,200 full-time food processing jobs in southern Idaho. In addition, the
transportation industry experiences a loss of another 350 jobs as the associated transportation services are
no longer needed.

In addition, Idaho’s Food Processing industry experiences a profound change in the marketplace for its
primary Idaho product – the frozen processed potato in the form of a French fry. The baby-boom generation,
the largest demographic component of the US population is aging, and becoming more health conscious.
Nationwide, demand for frozen French fries declines and productivity gains in the production of frozen potato
products accelerated rate of job losses the state’s Food Processing industry.

Increased restrictions and/or higher costs associated with the grazing of cattle on federal lands causes a
decline in the number of cattle raised in Idaho and another decline in Idaho’s food processing employment.

Idaho’s Mining and Agricultural industries accelerate their rate of decline in terms of output and employment.

In the Low Growth Scenario Idaho’s “high-tech” manufacturing industries of Non-electrical Machinery,
Electrical and Electronic Equipment, and Instruments are not immune from the slower rates of economic
growth. The current recession permanently cripples some of the state’s high-tech firm’s.

Furthermore, Micron Technology changes production practices at its Boise plant. Currently, Micron
Technology produces, as a computer memory chip – needing no further processing – as a final product from
the Boise fabrication plant. However, many other US computer chip makers only manufacture the “wafer” at
their US production plants. The “wafer”, with its hundreds of computer chips etched and imprinted upon them,
is then shipped to an overseas production facility for testing, final processing, and packaging. They commonly
cite lower labor costs overseas as their primary reason for splitting the production process in this manner.
The Low Growth Scenario assumes that Micron Technology changes their Boise operations in order to take
advantage of the potential labor cost savings available overseas. In the Low Growth Scenario, this policy
change causes the loss of nearly 5,000 manufacturing jobs in Idaho Electrical and Electronic Equipment
Industry.

The Low Growth Scenario’s projected manufacturing employment losses and accelerated rates of declining
employment, in turn, dampen employment growth in the secondary industries found in the affected and
nearby communities. Again, these secondary industries include employment in: Transportation,
Communications, and Utilities; Construction; Wholesale and Retail Trade; Finance, Insurance and Real
Estate; the Service industries; and local serving elements of Government.

In the Low Growth Scenario other industry sectors economy do not provide significant contributions to future
employment gains. Employment at the US Department of Energy’s Idaho Nuclear and Environmental
Laboratory (INEEL) are cut as federal funding is further curtailed.

Mountain Home Air Force Base would experience a slow attrition in its capability and a gradual contraction in
the number of total assigned military personnel in the Low Growth Scenario. The Gowen Field National
Guard facility in Boise would also contract from its current level of nearly 1,000 full-time assigned military
personnel to nearly 800 in the Low Growth Scenario.

Historically, federal government civilian employment in Idaho has been on a path of slow decline for many
years. Federal government employment in the state has always had a very large proportion dedicated to the
management and maintenance of the federal forests and rangelands. These management functions have
been cut to the barest levels over the past two decades. The High Growth Scenario anticipates that federal
employment associated with the management of federal lands will stabilize in the future. However, the rate of
growth in Idaho federal government employment that is primarily serving the local population would decrease
as the state’s population growth slows.

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2005 - 2009 Integrated Resource Plan

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Some of Idaho’s corporate headquarters would experience employment losses as market forces and financial
conditions force them to cut operating expenses. In addition, corporate mergers and/or acquisitions could
force the closure of one of the state’s larger call center operations with a resultant loss of nearly 1,000 jobs

Population

In the High Growth Scenario Idaho’s natural rate of population growth (population, plus births, minus deaths)
remains near current levels – about 1.1% per year. However, the economic outlook with a projected high rate
of employment growth in Idaho subsequently produces a high level of population in-migration to the state.

In the High Growth Scenario Idaho population is projected to increase at an annual average compound rate
of 1.9% per year over the 2001 to 2020 period. Statewide population in the High Growth Scenario is projected
to increase by 549,000 from 1,311,000 in 2001 to 1,860,000 in the year 2020. Furthermore, nearly 80% of
that population growth is projected to occur in southern Idaho.

In the Low Growth Scenario Idaho’s previously-described natural rate of population growth declines from its
current level – near 1.1% per year – to a level that more closely matches the projected natural rate of US
population growth – 0.7% per year. In addition, the Low Growth Scenario economic outlook with a projected
low rate of employment growth in Idaho produces a modest level of population out-migration as Idaho fails to
produce jobs at a rate high enough to satisfy the future job seekers.

In the Low Growth Scenario Idaho population is projected to increase at an annual average compound rate of
1.1% per year over the 2001 to 2020 period. Statewide population in the Low Growth Scenario is projected to
increase by 296,000 from 1,311,000 in 2001 to nearly 1,607,000 in the year 2020. As in the High Growth
Scenario, the expectations are that nearly 80% of that projected population growth will occur in southern
Idaho.

Households

The number of households in an area or region is a key factor utilized by many businesses in making
estimates of the current or future customer base that they may serve. Historically, in Idaho as well as in the
nation, the rate of household formation has exceeded the rate of population growth. During the 1970s and
1980s an increasing divorce rate, in conjunction with a delay in the age of first marriage, spurred household
growth. In this forecast no specific changes are assumed concerning these sociologic characteristics; i.e.,
divorce rates and age of first marriage are not assumed to move up or down in either the High Growth or Low
Growth Scenarios. The High and Low Growth Scenarios do project that changes in personal income growth
will cause either increases or decreases in the rate of household formation. This phenomenon is due to the
greater propensity for young adults to leave home and form their own households in prosperous periods, but
not as quickly in periods of recession.

During the 1970s, Idaho experienced a strong 3.9% annual average rate of household formation. At the same
time the national rate of household growth was 2.2% per year. In the decade of the 1980s, a period of slower
economic and population growth in Idaho, the state’s rate of household formation slowed to a 1.1% annual
rate, while the nation posted 1.7% annual gains. From 1990 to 2000 Idaho households increased by nearly
2.6% per year – producing an absolute gain of nearly 104,000.

In High Growth Scenario of the 2003 Economic Forecast, the number of households in Idaho is predicted to
increase at an annual average rate of 2.1% per year, yielding an absolute increase of 226,000 households in
the 2001 to 2020 period. As with the High Growth Scenario population forecast nearly 80% of that population
growth is projected to occur in southern Idaho with the Intermountain Gas Company service area.

In Low Growth Scenario, the number of households in Idaho is predicted to increase at an annual average
compound rate of 1.3% per year, yielding a modest absolute increase of nearly 134,000 households during
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2005 - 2009 Integrated Resource Plan

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the 2001 to 2020 period. And still, expectations are that slightly over 80% of the Low Scenarios; projected
household gains will occur in southern Idaho.

The following graphs illustrate the relationship between the three economic scenarios for the annual total
households forecast and the annual additional households forecast for the IGC service territory counties.

A N N U A L A D DITI O N A L H O U S E H O L D S F O R E C A S T
2005 - 2009
0
4,000
6,000
8,000
10,000
12,000
FY05 FY06 FY07 FY08 FY09
H I G H G R O W T H
B A S E C A S E
L O W G R O W T H
ANNUAL TOTAL HOUSEHOLDS FORECAST
2005 - 2009
350,000
360,000
370,000
380,000
390,000
400,000
410,000
420,000
430,000
FY05 FY06 FY07 FY08 FY09
HIGH GROWTH
BASE CASE
LOW GROWTH
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2005 - 2009 Integrated Resource Plan

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Market Share Rates
IGC utilizes market penetration rates that vary across the service territory. These regional penetration rates
are applied to the IGC service-territory counties within the three specific regions: west, central, and east.
These penetration rates are the ratio of IGC’s additional residential new construction customers to the total
building permits in those regions. Forecast additional households multiplied by the regional market
penetration rate equals the anticipated residential new construction customers.
IGC derives the regional market penetration rates by dividing the fiscal year regional residential new
construction sales total by the number of regional residential building permits compiled by the Wells Fargo
Bank Construction Report (“Wells Report”). The Wells Report arranges the data by city, as well as
unincorporated portions of the more populous counties in Idaho. These city/county tallies are reconciled to
IGC’s residential sales by IGC’s company town codes for valid comparison, and are then collapsed to the
county level.
IGC also develops another market penetration rate by way of the county construction reports which IGC
marketing and construction personnel use in prospecting for new construction customers. Again, as above,
the residential new construction sales in the specific areas covered by these reports are divided by the total
dwellings listed in these reports, to derive the market penetration rate. The areas covered here are the major
population centers in the IGC Service Territory: Ada/Canyon County, Twin Falls/Wood River Valley,
Pocatello/Soda Springs, and Idaho Falls/Rexburg. These market penetration rates are derived month by
month, and are compared and reconciled to the market penetration rates derived using the Wells Report.
The market penetration rates used in the customer forecasting varied somewhat when going into the future
out of anticipated market share gains in the Central and Eastern regions. Those for the West remained
relatively static through the forecast period, since they are already near 100%. The same set of market
penetration rates was used in the base case, high growth, and low growth scenarios.
MARKET PENETRATION RATES

Western Region
Central Region
Eastern Division
FY05
99%
95%
90%
FY06
99%
95%
92%
FY07
99%
95%
92%
FY08
99%
95%
94%
FY09
99%
95%
94%

The following graph illustrates the relationship between the three economic scenarios for the annual
residential new construction growth forecast for 2005 – 2009:
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2005 - 2009 Integrated Resource Plan

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ANNUAL RESIDENTIAL NEW CONSTRUCTION GROWTH
0
2,000
4,000
6,000
8,000
10,000
12,000
FY05 FY06 FY07 FY08 FY09
HIGH GROWTH
BASE CASE
LOW GROWTH

Conversions
The conversion market represents another source of customer growth. IGC acquires these customers when
the homeowner replaces an electric, oil, coal, wood, or other alternate fuel source furnace/water heater with a
natural gas unit. IGC forecasts these customer additions by applying regional conversion rates based on
historical data and future expectations. During a high and low growth scenarios, the rates are adjusted to
maintain reasonable expectations within the context of those alternative economic climates. The following
table shows, by region the assumed conversion rates over the five-year period. These rates represent the
percentage of new construction additions which will be conversions.
REGIONAL CONVERSION RATES

Western Region
Base Case
High Growth
Low Growth

Central Region
Base Case
High Growth
Low Growth

Eastern Division
Base Case
High Growth
Low Growth
FY05

17%
15%
40%

37%
34%
130%

36%
35%
36%
FY06

19%
18%
25%

38%
34%
65%

37%
35%
55%
FY07

21%
19%
25%

39%
35%
60%

38%
35%
55%
FY08

23%
19%
25%

40%
35%
45%

45%
32%
43%
FY09

25%
21%
23%

41%
35%
42%

45%
32%
40%

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2005 - 2009 Integrated Resource Plan

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The following graph illustrates the relationship between the three economic scenarios for the annual
residential conversion growth forecast for 2005 – 2009:

ANNUAL RESIDENTIAL CONVERSION GROWTH
1,200
1,400
1,600
1,800
2,000
2,200
2,400
FY05 FY06 FY07 FY08 FY09
HIGH GROWTH
BASE CASE
LOW GROWTH

Small Commercial Customers
Small commercial customer growth is forecast as a certain proportion of new construction customer
additions. The logic being that as household growth drives the major proportion of IGC’s residential customer
growth, household growth therefore drives small commercial customer growth. New households require
additional new businesses to serve them. Based on recent IGC sales data, this ratio of small commercial
customer growth to new construction residential varies across the IGC system, and thus different regional
rates for small commercial customer growth are used, and are as follows:
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2005 - 2009 Integrated Resource Plan

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REGIONAL SMALL COMMERCIAL CUSTOMER TO RESIDENTIAL NEW CONSTRUCTION CUSTOMER
GROWTH RATIOS

Western Region
Base Case
High Growth
Low Growth

Central Region
Base Case
High Growth
Low Growth

Eastern Division
Base Case
High Growth
Low Growth
FY05

7%
7%
7%

12%
12%
12%

15%
15%
15%
FY06

7%
7%
7%

11%
11%
11%

15%
15%
15%
FY07

8%
8%
8%

15%
15%
15%

16%
16%
16%
FY08

8%
8%
8%

15%
15%
15%

16%
16%
16%
FY09

9%
9%
9%

15%
15%
15%

16%
16%
16%

The following graphs show the annual additional, as well as the annual total small commercial customers for
the period 2005 – 2009:

ANNUAL ADDITIONAL SMALL COMMERCIAL CUSTOMERS
2005 - 2009
200
300
400
500
600
700
800
900
1,000
1,100
FY05 FY06 FY07 FY08 FY09
HIGH GROWTH
BASE CASE
LOW GROWTH
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TOTAL ANNUAL SMALL COMMERCIAL CUSTOMERS
2005 - 2009
24,000
26,000
28,000
30,000
32,000
FY05 FY06 FY07 FY08 FY09
HIGH GROWTH
BASE CASE
LOW GROWTH
Intermountain Gas Company
2005 - 2009 Integrated Resource Plan

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INDUSTRIAL FORECAST

Introduction

A survey of the industrial customers served by Intermountain Gas Company was completed in the Spring of
2003, to determine each customer’s projected natural gas usage. The survey included a cover letter
explaining the intent of the requested information with the assurance that all responses would remain
confidential. The survey form was sent to the management of each of Intermountain’s 114 large volume
contract customers and identified their historical usage on an annual peak month and peak day basis for the
past two years ending 2003. This information helped provide a basis for each customer to determine their
future natural gas requirements. Additional information was requested as to each customer’s alternative fuel
capabilities and if there was a desire for additional service options from Intermountain.

The results of the survey was used to forecast three distinct and separate large volume customer forecasts
(High Demand, Base Case and Low Growth) for a six year period, commencing in 2004. The projections
incorporate information from the customer’s management, engineers and marketing personnel regarding
plant expansion or modification, equipment replacement and anticipated product demand. Other forecast
data was then utilized to adjust the survey data base for two of the three forecasts (Base Case and Low
Growth). The 114 customers were further refined into six separate sub-groupings comprised of:

· Seventeen potato processors
· Forty other food processors which include sugar, milk, beef and seed companies
· Four chemical and fertilizer companies
· Twenty light manufacturing companies including electronics, paper and asphalt companies
· Twenty schools and hospitals and
· Thirteen other companies

All customer were assumed to remain on their current tariff while all new customers, if less than 500,000
therms, were assumed to be an LV-1 Customer and those over 500,000 annual therms would be T-4.

High Demand Forecast

The High Demand, or most optimistic forecast figures incorporate usage data directly from the survey with
minor adjustments. The increase from the 2005 annual usage of 226,994,368 therms was projected to
increase 35,426,964 therms, or 3.7 % through the forecasted period of FY 2009. The table below
summarizes the changes over this period:

High Demand Forecast by Market Segment
(Therms)

FY 05

FY 06

FY 07

FY 08

FY 09
Compound
Rate of
Growth
Potato Processors 86,261,000 88,148,000 89,836,000 90,720,000 94,138,000 2.2%
Other Food Processors 65,806,510 66,342,510 67,130.510 67,511.510 68,203,510 0.9%
Chemical & Fertilizer 28,810,000 28,810,000 28,360,000 27,960,000 27.960,000 -0.7%
Manufacturers 19,431,655 18,854,000 19,376,000 19,394,000 19,601,000 0.2%
Institutions 11,829,353 12,402,074 12,485,501 13,509,139 13,572,992 3.5%
Other 14,855,850 38,725,430 38,539,030 38,831,630 38,945,830 27.2%
Total High Demand
Forecast Therm Sales
226,994,368 253,282,014 255,727,041 257,926,279 262,421,332 3.7%

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2005 - 2009 Integrated Resource Plan

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A. Potato production and consumption was projected to return to the FY01 level, the highest usage for
this group in the past four years. This level would steadily increase from the FY05 projection of
86,261,000 therms, reaching the maximum in FY09 with an increase of 7,877,000 therms or 2.2%.
This assumes that oil prices would not impact the projected usage and no new plants are built, other
than those currently in operation.

B. Other Food processors were projected to increase with the addition of four new customers in FY 05,
06 and 08. The anticipated customers included a malt plant, a seed processor, and two existing
small food processors who are expanding their usage above 200,000 therms. All increases by this
group, as projected by the individual customer surveys, were included. The total projected increase
was 2,397,000 therms, or 0.9% over the 2005 projection of 65,806,510 therms.

C. The Chemical/Fertilizer group is projected to decrease 850,000 therms from the FY05 projection of
28,810,000 therms or 0.7%. The forecast projects the shut down of a customer’s facility in FY08 and
expansion of one of the four customers in this group. The projection assumes imported fertilizers will
not further erode this groups gas usage over the six year period.

D. The Manufacturing Group was increased a total of 169,345 therms, or 0.2% from the FY05 projected
usage of 19,431,655 therms. This is due to the closing of two plants and a projected addition of a
new manufacturing facilities in FY05 of 400,000 therms and another in FY 09 of 200,000 therms.

E. The Institutional group which is made up of Schools and Hospitals was projected by the survey to
increase 1,743,639 therms or 3.5% over the five year period from the FY05 volume of 11,829,353
therms. The prime reason for the increase is due to additional buildings being built, including the
continuing expansion of BYU Idaho.

F. The Other group was anticipated to increase 24,089,980 therms from the 05 usage of 14,855,850
therms or 27.2%. The most significant increase is due to the projected installation of a electrical
generator in FY06.

Base Case Forecast

The projected scenario was based upon the survey and assumed the agriculture economy will return to the previous
production in the near future. Additional adjustments were made in the late fall to reflect known changes of existing
customers. The projected usage for the Base Case increased 29,863,964 therms, or 3.2% from the FY05 forecast.

Base Case Forecast by Market Segment
(Therms)
FY 05 FY 06 FY 07 FY 08 FY 09 Compound
Rate of
Growth
Potato Processors 83,348,000 84,927,000 84,957,000 85,289,000 85,322,000 0.6%
Other Food Processors 65,166,510 64,842,510 66,630,510 66,811,510 67,703,510 1.0%
Chemical & Fertilizer 28,810,000 28,810,000 28,360,000 27,960,000 27,960,000 (0.7%)
Manufacturers 19,031,655 18,854,000 19,376,000 19,394,000 19,401,000 0.5%
Institutions 11,829,353 12,402,074 12,485,501 13,509,139 13,572,992 3.5%
Other 14,855,850 14,215,430 14,539,030 38,831,630 38,945,830 27.2%
Total Base Case Forecast
Therm Sales
223,041,368 225,561,014 226,348,041 251,795,279 252,905,332

3.2%

A. The Potato Processing Group was projected to increase 1,974,000 therms or an increase of 0.6%
from a usage of 83,348,000 therms in FY05. The forecasted yearly usage declined in the first several
years due to; 1) the assumption that the general demand for processed potatoes would a remain low,
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2) the assumption that the price of natural gas would remain higher than alternate fuel oil and the
continued oil usage by 3 customers, 3) the closure of JR Simplot in FY04.

B. Other Food Processors is projected to increase 2,537,000 therms, or 1.0% from 65,166,510 therms.
The primary reason for the increase is due to a new malting plant, a cattle feeding operations and 2
small food processors coming on line in the Fiscal years of 05, 06 and 09. All other customers
forecasted a small increase over the 5 year period.

C. The Chemical /Fertilizer Group is projected to decline 850,000 therms from the FY05 projection of
28,810,000 therms, or 0.7%. The reason for the decline is due to one customer shutting their plant
down in fiscal 08 while one customer is forecasted to increase gas usage approximately 30%. The
forecast assumes imported fertilizers will not further erode this group over the next six years.

D. The Manufacturing Group was projected to increase 369,345 therms or 0.5% from the projected
usage in FY05 of 19,031,655 therms. This is due to a concrete manufacturing plant shutting down
and the closure of a cattle feeding facility in FY05. On the positive side a new manufacturing
(electronics) plant is projected to startup in FY06.

E. The Institutional Group is projected to increase 1,743,639 therms or 3.5% from FY05 through FY09.
The increase, per the survey, was due to new buildings for schools and hospitals being built.

F. The Other Group is projected to increase from 14,855,850 therms or 27.2% primarily due to the
projection of an Electrical generator being brought on line in FY08. Several customers projected a
declining usage due to the addition of up-dating their equipment.

Low Growth Scenario

The projected usage for this scenario is based upon the assumption that the overall economy will be weaker
with lower natural gas sales due to the continued higher cost of gas and the general agriculture economy
remaining less than favorable. The change for the Low Growth Scenario is a total increase of 1,623,964
therms, or 0.2%, as shown below.

Low Growth Forecast by Market Segment
(Therms)

FY 05

FY 06

FY 07

FY 08

FY 09
Compound
Rate of
Growth
Potato Processors 82,298,000 82,527,000 82,557,000 82,889,000 82,922,000 0.2%
Other Food Processors 64,736,510 64,482,510 64,740,510 64,091,510 64,783,510 0.0%
Chemical & Fertilizer 28,810,000 28,810,000 28,360,000 27,960,000 27,960,000 -0.7%
Manufacturers 19,431,655 18,854,000 19,376,000 19,394,000 19,401,000 0.0%
Institutions 11,829,353 12,402,074 12,485,501 13,509,139 13,572,992 3.5%
Other 14,855,850 14,725,430 14,539,030 14,831,630 14,945,830 0.2%
Total Low Growth
Forecast Therm Sales
221,961,368 221,801,014 222,058,041 222,675,279 223,585,332 0.2%

A. Potato Processors; The price of natural gas was assumed to continue to be higher than the
delivered price of oil, resulting in the lowest gas usage for the potato processing group in the past
four years, which occurred in FY02. Additionally, the general potato consumption was assumed to
remain depressed over the next five years, and gradually returning in the sixth year, or FY09. This
group increased 624,000 therms, or 0.2%, from the projected usage of 82,409,600 therms in FY05.
This included the shut-down of the JR Simplot Heyburn facility in FY04 and a reduction by several
processors.

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B. Other Food Processors: This Group was projected to increase 47,000 therms. The milk processors
were held to their current projections after FY05, based upon the assumption existing siting
restrictions will further limit any new dairy milking facilities. Also the sugar industry will decline 10%
each year beginning in FY05 through FY09, as the price of natural gas increases against the
delivered price of coal. All other customers were held to to their projected usage.

C. The Chemical / Fertilizer group was projected to decrease 850,000 therms from the FY05 projection
of 28,810,000 therms or 0.7%. The forecast projects the shut down of a customer’s facility in FY08
and an increase of approximately 30% of one of the four customers in this group. The projection
assumes imported fertilizers will not further erode this groups gas usage over the six year period.

D. The Manufacturing Group was projected to decline 30,655 therms from the projected usage of
19,431,655 in FY05. This is due to a concrete manufacturing plant shutting down and the closure of a
cattle feeding facility in FY05. On the positive side a new manufacturing plant is projected to startup
in FY06.

E. The Institutional Group is projected to increase 1,743,639 therms, or 3.5% from FY05 through FY09.
The increase, per the survey was due to new buildings for schools and hospitals being built during
the forecasted period.

F. The Other Group is projected to increase from 14,855,850 therms, or 89,980 therms, or 0.2% due
primarily to customer projections of upgrading their equipment.

Firm Contract Demand:

The survey requested information as to each customer's future peak requirements along with their forecasted
annual usage. In discussing this issue with many of the largest customers, their peak day may not increase,
but their off peak day requirements would, i.e. less week-end downtime. The individual customer's peak day
requirements will be used to analyze potential future upgrades to existing laterals serving each community.
The existing and any new customer's Maximum Daily Firm Quantity (MDFQ) for each of the Large Volume
Firm Services (LV-1), Firm Transportation Service (T-1) and the Firm Transportation Service with Maximum
Daily Demand (T-2) will not be increased over the projected period. This is due to the recognition or decision
that the incremental firm transportation capacity, as contracted with Williams Pipeline Company, would create
additional cost to all customers. Additionally, each of the three tariff services, as listed above, are limited to
annual usage less than 500,000 therms per year. The current peak day firm therm requirements or demand
for the large volume contract customers by type of service are as follows:

Tariff
Total Firm Daily
Demand Requirements
(Therms)

Large Volume Firm Sales Services (LV-1)

16,825
Firm Transportation Services (T-1) 138,897
Firm Transportation Service with Maximum Daily Demand (T-2) 55,070

Total 210,792

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SAMPLE OF SURVEY COVER LETTER

April 27, 2001

customer name
address
city, state, zip

Re: customer name

Dear __________

In order to meet your future natural gas needs, we will need a projection of your future incremental
requirements on an annual, monthly, and peak day basis. To assist in your projection, we have included
historical usage information for the prior two years (beginning in January 1999) on the enclosed survey form.

The increasing natural gas usage that has taken place over the past five years as a result of the grown in the
residential and commercial sector, and the expanding industrial requirements in southern Idaho, has
demanded additional emphasis on forecasting our customer's future needs. An Order from the Idaho Public
Utilities Commission also requires Intermountain Gas Company to document its supply and demand
forecasting efforts as an added assurance that we are meeting our customer's needs at the lowest system
cost consistent with supply reliability.

We want to re-emphasize our commitment to continue reliable firm large volume sales and firm transportation
services to you as a valued customer of Intermountain Gas Company.

We appreciate your busy schedule and the effort required to complete this survey. However, only with your
assistance will we be able to accurately plan for the future to continue to provide you with the highest quality
service. Please return your completed survey, including any comments you have by May 18th, 2001. After
evaluating the responses, I will contact you concerning our plans for the future.

Should you have any questions, or if I can be of assistance to you, please call me at [phone].

Very truly yours,

Daniel A. McAlister
Industrial Services Manager

DAM/slk

Enclosure
Intermountain Gas Company
2005 - 2009 Integrated Resource Plan

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SAMPLE OF SURVEY FORM

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USAGE PER CUSTOMER UNDER DESIGN DEGREE DAYS

This section of the Intermountain Gas Company (IGC) Integrated Resource Plan (IRP) describes and
summarizes the usage per customer calculation under design weather conditions. These results, combined
with the customer forecast results, develop the load duration curve for the IRP. The following flowchart
illustrates the development of daily residential and small commercial market therms utilizing design degree-
days.

Regression Equation
(for each month) WX Norm.
Model Customers 65 HDD
Daily Baseload therms
per Customer
Daily therms per
customer per Degree
Day
Design
Degree
Days
Design Therms
per Customer
Customer Forecast
(IRP)
Total Core Market
Daily Design Therms
Peak Month
November - February
Non-Peak Months
March - October
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The following sections more fully explore the derivation of the usage per customer assumptions during peak
months and non-peak months. Both sections discuss the respective methods used to calculate usage per
customer per degree day and the application of the resulting equations.

CUSTOMER USAGE DURING PEAK MONTHS

Data and Variables
Usage per customer per degree-day under design weather is based upon a multiple regression equation for
each month during the peak heating season of November through February.

The dependent variable, peak usage per customer, is calculated by dividing the total residential and small
commercial market sendout for each day during each of the peak months by total residential and small
commercial customers for each day during each of the peak months. Daily customers are developed by
evenly spreading the difference between the customers at the beginning of the month and the customers at
the end of the month to the days of the month.
A thirteen-year historical database, using data from the winter of 1989/1990 through the winter of 2002/2003,
was used to develop the dependent variable (See Exhibit 3, Appendix A). A starting point of 1989 was
selected for the database, because of a structural shift that has occurred in the data. During the late 1980’s
and early 1990’s, the effects of tighter Federal and State equipment efficiency standards and new building
codes, which incorporate higher efficiency standards, have led to a decrease in usage per customer per
degree day (See “The Efficient Use of Natural Gas”). In addition, the rapid customer growth of the 1990’s
means that an increasing percentage of the customer base is using this more efficient equipment. As a result
of this change in usage per customer, models using the 1989/90 through 2002/03 data provided a much
better statistical fit than models that included the older data.

The independent variables consist of the actual sixty-five heating degree-days (65HDD) for each day during
the peak months and a weekend binary variable. The weekend binary variable, a one (1) if Saturday or
Sunday, and a zero (0) if Monday through Friday, helps establish whether or not a relationship exists
between usage and the weekend.

Methodology and Results
A regression equation was developed for each of the peak months. The independent variables, daily actual
65HDD and weekend binary, were regressed against the dependent variable, daily usage per customer, to
detect any relationship between the dependent and the independent variables (See Exhibit 3, Appendix B).
The weekend binary variable was not significant in the February model, so the 65HDD variable is the only
variable remaining in the February model. The models for November, December and January all include
both the 65HDD variable and the weekend binary variable.

In order to evaluate models, two statistical measurements were employed: the adjusted R2 and the F-statistic.
The adjusted R2 determines what percent of the variability in usage is explained by the independent
variables. The F-statistic determines whether or not the regression equation is significant. A table of the
adjusted R2 and the F-statistic follow:

PEAK-DAY USAGE REGRESSION EQUATION RESULTS

MONTH

ADJUSTED R2

F-STATISTIC
NOVEMBER 89.0% 1700.04
DECEMBER 89.3% 1806.74
JANUARY 88.0% 1581.24
FEBRUARY 61.6% 587.95

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After the regression equations were developed, design degree-days were used in the models in place of
actual 65HDD to calculate the daily usage per customer during the peak months. (See Exhibit 3, Appendix C-
E).

Customer Usage During Non-Peak Months

Customer usage during the non-peak heating months of March through October is based upon an average
usage calculation from Intermountain’s weather normalization model. First, baseload usage was removed
from the monthly usage per customer. Baseload usage is defined as the usage during July and August,
which is 24.0 therms per month. The remaining monthly therm usage from the weather normalization model
was then divided by customers and 65HDD to develop daily usage per customer per degree-day. The
following table shows the therms per customer per degree-day for each of the non-peak heating months.

USAGE PER CUSTOMER DURING NON-PEAK MONTHS

MONTH
THERMS/CUSTOMER/65HDD
MARCH 0.148
APRIL 0.128
MAY 0.102
JUNE 0.086
JULY 0.000
AUGUST 0.000
SEPTEMBER 0.092
OCTOBER 0.091

The daily usage per customer per degree day figure was then multiplied by the design degree days resulting
in weather sensitive usage per customer. Daily baseload usage was added to the weather sensitive usage
per customer to arrive at total usage per customer, under design weather conditions, for each of the non-
peak heating months.

Total Daily Usage

The usage per customer for both peak and non-peak periods was then multiplied by the total residential and
small commercial customers for that day (See Customer Forecast). This calculation results in total usage for
each day.

Total daily usage for each month varied depending upon the customer growth assumption that was used (i.e.
low growth, baseline, or high growth) (See Exhibit 3, Appendix C-E).

Usage by Customer by Geographic Area

Intermountain Gas Company has recently installed additional meters on targeted areas of its system that
measure natural gas throughput in addition to the existing pressure measurement. These new meters,
located on the Idaho Falls and Sun Valley Laterals, will facilitate a more geographically specific correlation
between consumption and Heating Degree Days (“HDD’s”) thereby refining the usage forecasts for these
laterals.

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DESIGN HEATING DEGREE DAYS2

Intermountain Gas Company uses the demand forecast to determine and plan for future annual and peak day
firm capacity requirement. The design degree-days provide a means to distribute the heat sensitive (core)3
load portion of the forecast on a daily basis. See Design Degree-Days by Month on Table #1.

Design Development

A review of the last thirty years' of heating degree data from NOAA4 (see Tables #2 and #3 for Degree-Day
data) was made to determine the limits of a design year. Due to their geographic locations, data from the
Boise and Pocatello weather stations was used to represent the total distribution system's design degree-
days. The review revealed Intermountain's coldest twelve consecutive months to be the fiscal year 1985
(October 1994 through September 1995). This period, with certain modifications, represents the basis for the
design.

Design Modification

The coldest month for the last thirty years was December 1985 (1638 degree-day). For design purposes,
December 1985 was substituted for January (peak month).

The addition of degree-days to the remaining non-peak months (one percent) to assume the potential for
colder weather.

The summer months (May through September) were normalized.

The total design was made to assume a bell-shaped curve with peak at mid-January (see Graph #1). This
ensures a core peak to coincide with the peak industrial load that historically occurs in mid-January.

Design Peak Day Modification

The coldest day on record occurred on December 22, 1990 and was an 82 degree day average for Boise and
Pocatello (i.e. Boise 82 degree day and Pocatello 81 degree day). For design purpose, an 84-degree day
was used to reflect colder temperatures that have occurred in eastern Idaho. The average of the two
reporting stations is representative of the temperature extremes that may be expected in each location
throughout Intermountain Gas Company's service area. Additionally, although the peak day occurred in
December, it was assumed the peak day would occur in January for planning purposes.
2 The methodology was reviewed and approved by Idaho Climatologist Myron Molnow, Moscow, Idaho 3 The core market (heat sensitive) usage per customer as determined by the regression correlation analysis is multiplied by the
design degree days to determine daily usage. 4 NOAA - National Oceanic and Atmospheric Administration
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HEATING DEGREE DAYS - NORMAL/ ACTUAL FY 85/DESIGN

Weighted Actual Design - Bell
Month Normal (30 yrs) Fiscal 1985 Shaped Curve

October 452 605 524
November 818 834 907
December 1129 1350 13322
January 1166 1512 16382
February 884 1196 12102
March 723 1026 963
April 484 435 585
May 248 236 296
June 39 69 99
July 0 0 7
August 0 35 25
September 99 288 176
Total Year 60423 7586 77621

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The resultant Degree Day Design compares to: (See graph on Page 32)
1 27.8% colder than normal year; 2.3% colder than the 1984/85 year
2 3.0% colder than the 1984-85 three month period December through February (critical planning months due to
pipeline capacity restraint and rationing of storage gas)
3 Weighted 30 year normal ending FY2003

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Table #2

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Table #3

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HEATING DEGREE DAY

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TRADITIONAL SUPPLY SIDE RESOURCES

Overview

Traditional supply resources are those that the Company normally uses on a day-in and day-out basis to
deliver natural gas to its customers. More specifically it is the natural gas supply – or the commodity – the
end-user burns, the physical pipe through which the gas moves to reach the end-user, and certain storage
facilities where natural gas is stored for use in high peak periods. Intermountain's gas supply management
strategy involves meeting all firm customer gas and/or transportation requirements while minimizing costs
and associated risk by utilizing a portfolio of diverse supply resource options. The following section will
identify and discuss each of the available supply resources and describe how each part may be utilized in a
larger portfolio approach to gas delivery management.

Background/Historical Perspective

Natural gas is a naturally occurring mixture of hydrocarbon gases found in geologic formations under ground.
It is principally methane and is produced by drilling into porous formations and extracting the hydrocarbons
using various techniques. The procurement and distribution of natural gas is in concept a straightforward
process. It simply follows the movement of gas from its original geological source through processing,
gathering and pipeline systems to end-use facilities where the gas is ultimately ignited and converted into
thermal energy. Intermountain physically receives all gas supply to its distribution system via citygate taps
with Northwest Pipeline (“NWP”), the only interstate pipeline with interconnects to Intermountain’s system.

A predecessor of NWP first brought natural gas service to the Pacific Northwest in the mid 1950's by
constructing pipeline facilities which began in Northwestern New Mexico and Southwestern Colorado and
continued Northward through Utah into Southern Idaho, then across Idaho, Eastern Oregon and Western
Washington. The pipeline then turned Northward up the I-5 corridor where it interconnected with Duke Energy
Gas Transmission ("DEGT" - formerly Westcoast Pipeline), a Canadian pipeline in British Columbia, near
Sumas, Washington (See Exhibit 4, Appendix A). Along its path, NWP also interconnects with National Gas
Transmission (“NGT” - formerly PGT) near Stanfield, OR as well as several other interstate and gathering
systems in Wyoming, Utah, Colorado and New Mexico. From those interconnects, Northwest receives gas
supplies from the gas producing regions in Alberta, British Columbia, Northwest Territories and the Rocky
Mountain region of the Western U.S. for delivery to utilities and other end-use customers located both on and
off its system.

Delivery of natural gas supply to end-use markets in the Pacific Northwest has evolved significantly in the
past 15 years. Up until the mid 1980's, the typical gas Local Distribution Company ("LDC") or utility, merely
“ordered” a certain quantity of natural gas each day from its local interstate pipeline company. The pipeline
was responsible for contracting with producers for the natural gas supply, managing the daily gas supply and
arranging for all required upstream pipeline capacity.

Under this strictly controlled and regulated environment, the natural gas industry in the late 1970's and early
1980's began to experience a decline in overall demand, particularly in the industrial market segment, as the
end-use market responded to gas prices which were artificially high vis-à-vis other energy alternatives. At the
same time, the Federal Energy Commission’s ("FERC") practice of setting high wellhead prices to ensure
adequate levels of reserve replacement discouraged producers from efficiently managing production and
deliverability. High prices encouraged producers to continue to add to the growing supply surplus even
though, in reality, no market existed for gas at the regulated prices set by FERC. Additionally, the pipeline
grid was inefficient so when peak demand periods did occur, no mechanism existed (i.e. a spot market) to
move the surplus, uncontracted-for supply to end-use markets.

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The result was capacity curtailments that were interpreted by the market as supply shortages. This mixed bag
of confusing economic signals was one of the key factors that led the Federal government to determine that
only a free and competitive marketplace could solve the problems then facing the gas industry.

Deregulation

Before the introduction of deregulation its policies, FERC strictly regulated all aspects of the interstate gas
delivery system including wellhead pricing, transport capacity, storage utilization and delivered-to-the-citygate
pipeline prices. Consequently, Intermountain simply reserved peak day delivered requirements from NWP,
"nominated" the level of expected demand for any given gas day, and paid NWP the tariff price for the level of
bundled services utilized. There existed no way for Intermountain to negotiate better prices, adjust its portfolio
to meet changing market conditions or temporarily sell off under-utilized "resources". Nor was any LDC
capable of planning for and executing a gas supply plan specific to its own needs to ensure it could serve and
satisfy its customers.

Beginning in the mid-1980’s, FERC began the process of leading the natural gas industry into a more
competitive environment by first decontrolling wellhead natural gas prices. Then FERC began to decouple the
interstate pipeline’s control on contracting for and purchasing natural gas from its physical capacity to move
the gas. The goal was to allow the market to not only price the natural gas, but also to turn natural gas into a
true commodity. Secondly, pipeline capacity and storage facilities needed to be provided to users in a
competitive, open-access environment. Armed with Congressional authority to introduce competitive market
forces into the interstate natural gas marketplace, FERC began to issue a series of Orders to deregulate the
natural gas market. Exhibit 4, Appendix A, Table 1 lists and describes some of the more significant legislative
actions and events which resulted in today’s decontrolled and deregulated gas industry, as well as several of
the ensuing FERC Orders by which these policy directives and laws were implemented.

While yesterday’s natural gas market was often constrained and gas supplies were often under produced and
over priced, today's competitive energy environment allows market signals to encourage capacity
enhancements. Producers are now driven by economic pricing signals to increase drilling and exploration for
natural gas and the interstate pipeline grid has grown so that capacity is less localized and the gas producing
regions in the U.S. and Canada are now a part of a larger, more efficient system. For example, where much
of the gas supply produced near the facilities of NWP was historically captive in the Pacific Northwest –
having no outlet to other regions – new pipeline construction and expansions have created additional
avenues for delivery into off-system regions from California to the Midwest. The benefit to Intermountain is
that producers are encouraged to continue enhancing deliverability.

Another benefit of deregulation is an increase in overall pipeline grid efficiency as gas supplies can move
quickly through once impassable capacity barriers, across vast regions to serve locations with the highest
demands. Within the producing areas, the only difference in natural gas pricing is the variable cost of
transportation between production points. While this new efficiency has led to new market growth for natural
gas, it has also lead to more competition among the Western and Midwestern U.S. markets for available gas
supplies, driving up prices in the Northwest generally. Gas producers now have more ability to send gas
supplies to markets willing to pay higher prices.

Another more localized effect is a higher annual load factor (the annual average throughput divided by peak
throughput) on NWP as deregulation has led to higher throughput. Consequently, the more efficient use of
capacity at times results in less operational flexibility for shippers and may interesting enough, result in less
frequent expansions by pipeline companies as needed capacity may be found via capacity release. This
deregulation phenomenon has placed Intermountain in a mega-regional marketplace where market
conditions from Western Canada and California to the Gulf of Mexico or Chicago, may affect the regional
market dynamics relating to supply availability, pipeline capacity and commodity pricing signals.

Today’s LDC is responsible to structure, arrange and manage its own gas supply and transportation portfolio
in order to meet the needs of its customers. As interstate pipelines are now only common-carrier transporters
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and no longer contract for gas supply, it is up to the individual LDC to properly plan and implement strategies
to ensure the availability of the necessary resources.

While the gas delivery environment has changed drastically in the past decade, Intermountain's commitment
to providing secure, reliable and price-competitive firm service to its customers has not. Whether the
customer desires burner-tip sales service, transport-only service or other unbundled service options,
Intermountain will, through its long-term planning process, continue to identify, analyze and utilize best-
practice strategies and implement procedures necessary to provide the value of service that its customers
expect.

Gas Supply

General. Intermountain is well positioned in a region with a diverse and stable gas supply base as the
Rockies and Western Canadian Sedimentary Basin (“WCSB”) producing fields continue to provide ample
production and deliverability. Historically, the PNW has enjoyed an advantage of low cost natural gas
because supply basins in this region were not well connected to the larger North American market. With
capacity additions to the interstate pipeline grid, this advantage has all but disappeared as we now compete
for gas supply with the broader national market. This new market efficiency has resulted in sustained higher
prices for this region as we now must compete with markets traditionally paying higher prices for gas supply
(See Exhibit No. 4, Chart 4.1).

The sustained higher market prices of recent years has once again peaked interest in the supply potential
from the Arctic regions of Alaska and Canada specifically in the Prudhoe Bay and Mackenzie Delta regions.
However, any deliveries from these basins will require a huge investment in new pipeline capacity, will take
years to complete and will require a long and difficult permitting process. As such, even the most optimistic
expectations push the initial deliveries of this potential gas supply well out of the term of this study.

Liquefied Natural Gas (“LNG”) imports are another supply source is currently generating much interest in the
marketplace. Most of this supply will come from foreign production and would be shipped in huge tankers to
receiving ports along the coast line of the U.S. While the North American market already imports some LNG
today, its overall impact to the market is nominal. However, some studies indicate that if today’s prices levels
are sustainable, LNG imports will continue to increase and within 20 years may equal nearly 10% of annual
gas usage. But as with the Artic gas supply, the huge investment required to build port facilities as well as
perceived safety issues and the lengthy permitting process, make significant imports of LNG during this
forecast period unlikely.

A significant change in most forecasts show increased pricing for the Pacific Northwest reflecting new
pipeline capacity in the Western U.S. and Canada which allow more gas supply to flow to the historically
higher priced markets in the Midwest and East coast. While prices are projected to remain robust, availability
is not expected to be an issue. Even during the high prices of 2000 and 2001, gas was available as long as a
market was willing to pay the market price. As well, issues relating to gas-fired generation, storage, hydro-
generation and gas-to-electric price spreads that plagued the market during the past few years appear to be
less critical as the competitive market adjusts for these factors.

Types and Pricing. During the early years of Open Access, Intermountain determined that a portfolio based
on firm supply contracts with a variety of reputable suppliers would provide the greatest level of reliability and
security for year-round delivery of gas supply. Firm supply (as opposed to best efforts or interruptible) is sold
with a supplier's assurance that, absent a defined force majeure event, 100% of the supply will be available
for delivery to the market on every day of the contract term.

The NYMEX natural gas futures provide the market with an excellent price discovery tool. Using the NYMEX
natural gas contract and/or associated derivative pricing has allowed Intermountain more flexibility in the way
it builds the portfolio. As well, stringent creditworthiness requirements, by financial institutions, give buyers
and sellers more confidence as to the financial viability of their contractual counterparties, notwithstanding of
length of the contracts. Because both buyers and sellers are generally unwilling to take unnecessary price,
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credit or market risk, the amount of gas traded with prices based on NYMEX-type financial instruments
continues to account for the majority of supply bought and sold.

One key element of term supply pricing is Load Factor. A producer is typically more willing to offer supply
under a high load factor contact. In fact, it has become increasingly difficult to purchase firm supply at
anything less than 100% load factor. Under such a contract, the supplier knows that absent any force
majeure event, the market will take the full volume of gas every day during the term of the contract.
Alternatively, under a less than 100% load factor contract, the market may only take gas during the peak
periods and release the supply to the supplier during lower usage periods when pricing is usually less
advantageous for the seller. Therefore, the supplier must stand prepared to re-market the unutilized supply
when the term market does not require it - often times at short notice and during periods when spot pricing is
relatively low. For this reason, suppliers normally require a premium to the market price or a demand charge
when contracting with low load factor markets. The load factor concept is an important consideration of
portfolio management as Intermountain seeks to obtain the most cost efficient supplies available.

Intermountain also utilizes other types of supply such as daily and/or monthly spot, seasonal supply, swing
and winter peaking. A recent addition to the portfolio is citygate deliveries. This supply source is simply where
a marketer bundles gas supply with interstate capacity and delivers supply directly to the LDC. The Company
also uses storage facilities to balance its loads and achieve an efficient supply portfolio (See Page 43,
"Storage").

Long-term supply has historically been priced at a premium to spot or index-based supply. In today’s market,
most buyers and sellers rely on the market index prices at various pricing points plus or minus a premium for
each given month. Using Nymex futures, either party is able to lock-in prices for future periods should those
prices meet the party’s requirements.

Spot gas is typically gas that suppliers, for various reasons, do not contact on a term delivery basis. The term
"spot gas" may apply to gas sold under differing terms including firm, interruptible, swing, day gas or best
efforts and is usually available at almost anytime at varying volumes, prices and contract terms. Spot gas
may be bought for one or several days a time, for one month or even for seasonal periods such as the
summer injection periods. During peak usage periods, spot may be difficult to find, be relatively expensive,
unreliable or may be available only on a day-to-day basis. Of course in non-peak months, spot is most often
readily found and is usually less expensive compared to firm supply. Intermountain generally purchases firm
spot supplies for a given month and as a rule, targets those suppliers with reputation for reliability.

Swing supply is gas that is very interruptible. Swing is most often utilized early in the winter periods in order
to preserve storage or during times when the loss of that supply would not result in curtailments to customers.
Swing is most often available during significant weather swings and is often the cheapest gas that can be
purchased due to its interruptible nature, but it can play an important role in a diversified portfolio.

Winter peaking supply is typically baseload volume purchased for the two-to-four winter peak usage months
to augment the storage withdrawal cycle. While these contracts may be structured in any number of ways,
they are ordinarily firm in nature and have 100% daily take commitments but often have price levels that
exceed month-to-month spot.

Supply Regions. Intermountain's natural gas supplies are located primarily in three producing regions:
British Columbia (BC) Canada, Alberta, Canada and the Rocky Mountain (or Domestic) region consisting of
production primarily from the states of Wyoming, Utah, Colorado and New Mexico. In general, the proportion
of purchases from the various supply basins is very dependent upon the mix of firm receipt capacity on the
various pipelines utilized (see “Transportation” below).

British Columbia. BC has traditionally been a source of abundant supply for the Pacific Northwest. Much of
the gas produced in the province is exported into the U.S. at an international interconnect point located near
Sumas, WA. Much of that supply had historically been somewhat captive to the region due to the lack of
alternative pipeline options into Eastern Canada or the Midwest U.S. However, the expansion of
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TransCanada Pipeline’s capacity into Eastern Canada and the completion of the Alliance pipeline delivering
supply into the Chicago area, eliminated that bottleneck.

While there continues to be an adequate supply from BC over and above provincial demand, new discoveries
in Northeast BC and the Northwest Territories are critical to future deliverability to export markets. Even
though these supplies must be transported long distances in Canada and over an international border, there
have historically been few political or operational constraints to encumber the delivery to Intermountain's
citygates. Recent deliverability studies by DEGT project moderate growth in reserves and future production.

Alberta. Production in this province has always been abundant. In fact, Alberta is believed to have the largest
natural gas reserves in the North American continent and annually produces 10 times the Pacific Northwest’s
yearly consumption. Since a 1993 National Gas Transmission (“NGT” formerly PGT) expansion that
increased the delivery of Alberta supply into NWP, Alberta supply continues to have importance within
Intermountain's portfolio. The Stanfield interconnect between NWP and NGT offers added operational
reliability and flexibility over other receipts points both north and south. Other positive factors influencing the
decision to purchase Alberta supplies are vast unrecovered reserves, extensive pipeline facilities, and access
to inexpensive production-based storage (see "Storage" below). Where these supplies once amounted to a
trickle, today’s purchases amount to approximately 37 percent of the Company's peak purchases.

One area of concern is the rapid production decline of wells drilled in the past few years. In response to the
price increases in 2000 and 2001, record numbers of rigs were drilling in Alberta. A large number of these
new well completions were in shallow reservoirs which produced huge amounts of natural gas early on, but
then declined rapidly. However, regions that are expected to be the next frontier for future exploration and
production are in basins requiring deeper well depths. These deeper wells generally do not have the robust
early production of the shallower wells but neither do they have the steep production decline curve and
therefore produce gas, at steadier rates, for much longer periods. However, drilling deeper wells also involves
greater cost. Again, as long as the producer can achieve adequate returns on investment, exploration, drilling
and increased production will continue.

Most recent reserve and production forecasts for Alberta are mixed in projections; some see increases and
others decreases. A recent Canadian National Energy Board (NEB) study projected that the Western
Canadian Sedimentary Basin (“WCSB”) has 266 Tcf of Ultimate Resource Potential, most located in Alberta.
However, Alberta is also considered a mature basin and other studies indicate that over the medium term,
producing entities’ plans for drilling and production may not replace natural declines in production. However,
new gas fields in Northern British Columbia and the southern areas of the Northwest Territories and the
Yukon indicate significant potential new supply pools likely exist and expectations are positive. In general, it is
projected that, at worst, any loss of Alberta production will be offset by increases in BC production. While the
short-run supply availability from Alberta may tighten somewhat, longer-term forecasts project marginally
increasing production.
Additionally, the northern most pipeline facilities in Alberta are well positioned to receive supply from the
Arctic regions should exploration and production commence in those basins.

Rockies (Domestic). Domestic supply has historically been the second largest source of supply for
Intermountain partly due to NWP requirements (see "Transportation") but also because the supplies have
been readily available, relatively inexpensive and highly reliable. Events such as NWP's expansions at
interconnects with off-system pipelines (e.g. Kern River) and the general effect of the deregulated and
competitive marketplace has tended to make supply in this region more price competitive with Midwestern
and California markets and consequently, more expensive than in the past.

Due to recent successful reserve finds, particularly in the Rockies tight sands and coalbed methane
producing basins, gas production in the region is projected to grow by 14% from 2004 to 2008. This growth
should provide ample gas supply availability throughout this forecast. However, recent experience indicates
that the traditional “gas bubble” of excess supply that was so prevalent in the 1990’s, is no longer a reality.
While the unprecedented price increases during 2000 and 2001 and the subsequent price strengthening in
2003 and 2004 were the result of many factors, clearly overall demand growth has exceeded supply growth
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over the latter part of the 1990’s and through 2004. But it is also apparent that the exploration and production
community can bring additional supplies to market quickly if prices are high enough to encourage adequate
investment.

Forecast production figures indicate that the Rockies have 233 tcf of ultimate production potential. The
Rockies’ basins are the only producing area in the lower 48 that are projected to show increased production
in the next decade. There are a few caveats however. First, domestic producers find it increasing difficult to
gain access to new areas to explore for natural gas. And it is also becoming more of an effort to obtain
permits from various governmental entities which greatly slows down the drilling process. But as long as
these concerns are appropriately addressed, free-market forces should continue to spur future exploration in
the Rocky Mountain regions. Additionally, with the help of new technologies, the Rockies should continue to
provide ample gas production for the region well into the future.

One area of concern is the NWP capacity constraint at Kemmerer, Wyoming (just east of the Idaho border)
which limits the amount of Rockies supply that can flow west into Idaho during peak periods. Taking
advantage of “segmentation” opportunities on NWP, the Company increased its allocation of firm capacity
rights from receipt domestic points flowing through the Kemmerer bottleneck into Idaho. This provided
Intermountain with the capacity necessary to transport Clay Basin withdrawals into Idaho. Because the cost
of physically increasing capacity through the Kemmerer constraint point would be exorbitant, the Company
will likely not increase its stake in Rockies supply unless additional released capacity can be obtained
through another firm shipper on NWP. Near-term outlooks project that the Company will continue to obtain
approximately 42 percent of its peak gas supply from the Rockies. (See Exhibit No. 5, Appendix B for Supply
Resource Summary.)

Transportation

General. Firm transportation capacity provides a mechanism whereby a pipeline will, on behalf of a
designated and approved shipper, reserve the right to receive and redeliver a certain amount of gas supplies
on that pipeline system to a specified delivery point. The major pipelines with which NWP interconnects can
be seen on Exhibit 4, Appendix A. Duke Energy Gas Pipeline (formerly Westcoast Transmission) in British
Columbia interconnects with NWP near Sumas, Washington and provides for the receipt of supplies
produced in BC as well as the Northwest Territories. An interconnect with Duke Energy Gas Transmission
(“DEGT” formerly PGT) near Stanfield, Oregon allows for the delivery of gas produced in Alberta into NWP.
Other major interconnects are with Colorado Interstate Gas in Southwestern Wyoming; Questar Pipeline in
Western Colorado and Eastern Utah; and El Paso Pipeline in Southwestern Colorado and Northern New
Mexico. These pipelines provide outlets for gas produced in locations stretching from Wyoming to New
Mexico. NWP also directly interconnects with producing and/or gathering areas in Wyoming, Utah, Colorado
and New Mexico.

Deregulation. All activity regarding transportation of natural gas supplies through any part of the interstate
pipeline grid continues to be under the review and regulatory oversight of FERC. The final step in the
deregulation process required pipelines to discontinue sales service and open the interstate transportation
grid to competition. Thus the pipelines’ former sales customers were directed to convert their sales
entitlements to firm transport capacity.

One of the more significant actions was FERC Order 636 which generally completed the task of providing a
more open and competitive marketplace by unbundling pipelines' gas purchasing obligation from their
transportation function. As a result, pipelines became common carrier transporters and no longer sold
bundled supplies. All shippers were compelled to provide their own supply and any shipper with unneeded
capacity could release it in the open market via the pipeline’s electronic bulletin boards ("EBB") or websites.
Therefore, any entity seeking new or incremental space on an interstate pipeline could potentially have
access to unused space through the capacity release mechanism. Other significant features of Order 636
were Straight-Fixed-Variable ("SFV") rate design, open market access to storage and Hub services, flexible
receipt and delivery point nominations and the shifting of system balancing responsibility from the pipeline to
the shippers and end-use customers.
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Another important feature of Order 636 allowed firm shippers to “release” unutilized capacity to others in the
marketplace who would willingly pay the market price to lease it for some predetermined period of time. This
allows Intermountain the opportunity to sell off unused capacity in off-peak and also to obtain additional
capacity if the need were to arise. A valuable offshoot of capacity release is the notion of “segmentation”.
This is a particular kind of release where the primary path can be divided into two or more separate pieces
along the receipt/delivery path where each piece still retains its applicable primary firm rights. Segmented
capacity allows Intermountain to segment one or more of the pieces of that capacity to be released to a
replacement shipper while retaining a segment for its own use. The amount the replacement shipper pays for
the “new” capacity is a cost savings to the releasing, or original, shipper. Intermountain has completed
several long-term segmented releases that enable to Company to retain the same level of overall firm
capacity while also obtaining a significant cost savings which are passed on to Intermountain’s customers.

The decoupling of capacity was critical in the unbundling process as natural gas molecules – or the
commodity - at any given supply point has little value unless a sufficient amount of transport capacity is also
available to effectuate delivery of the molecules to the end-use burnertip. As well, a party with firm transport
capacity but inadequate supply arrangements could find itself unable to use the capacity. Consequently, firm
natural gas supply and firm transport capacity must be utilized together to offer secure and reliable delivery of
natural gas to an end-use market’s burnertip. Clearly, possession of one without the other will in all probability
result in less than firm service and in all likelihood, increases the risk of supply failure.

As a condition of sales CD conversion, NWP required that shippers continue to source purchases in the
same proportion that the pipeline had sourced its sales portfolio: Approximately 58 percent of daily supply
was required to be sourced from Sumas to ensure the efficient operations of the pipeline. However, past
experience with NWP system dynamics has shown that any type of disruption due to normal maintenance,
extreme weather conditions or basin price variations, tend to result in pro-rata transport cuts and Operational
Flow requirements. This operational dissonance is particularly onerous for markets East of the corridor as it
most often occurs with South-flow supply from Sumas through the I-5 corridor.

Intermountain actively searched for ways to minimize these problems. One alternative was to move existing
receipt capacity or find new capacity at alternative points. Intermountain discovered there were also certain
transportation cost benefits to moving firm receipt capacity away from Sumas by using segmentation
opportunities. Consequently, Intermountain elected to “segment”, or move just over half of its firm receipt
capacity on Northwest from Sumas to Stanfield. This reduced its reliance on the amount of BC supply
purchased, from 58 percent of peak purchases in the late 1980’s, to approximately 22 percent today and
added a new level of diversity to the gas supply portfolio.

From the earliest days of deregulation, Intermountain fully embraced the idea of the efficiencies of the
competitive marketplace and consequently was the first Pacific Northwest LDC to convert 100% of its
applicable sales CD to transport capacity. When NWP implemented Order 636 on its system in 1994, the
Company had already been transporting 100% of its supply for six years. Intermountain was also the first
LDC in the Northwest to implement transportation tariffs behind its own citygates in order to allow its industrial
customers to benefit from the advantage of open access transportation.

The table below shows Intermountain's receipt point capacity through 2009 from each receipt area on the
NWP system. Through studies such as this, Intermountain reviews it capacity requirements and adjusts its
resources as needed.
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Intermountain Gas Company
Firm Receipt Point Capacity Through 2009
Volumes in MMBtu

Receipt Point 2004 2005 2006 2007 2008 2009
Sumas 41,146 41,146 41,146 41,146 41,146 41,146
Stanfield 76,800 86,800 86,800 86,800 86,800 86,800
Rockies 87,384 93,384 93,384 93,384 93,384 93,384
Storage 87,000 87,000 87,000 87,000 94,500 94,500
Citygate 25,000 25,000 25,000 25,000 25,000 25,000
Total 317,330 333,330 333,330 333,330 340,830 340,830

The Company utilizes this transport capacity to move purchased supplies to the citygate taps with NWP. Gas
is then moved from these various points through its own distribution system to provide various types of
delivery service to its customers. Residential and small commercial ("Core") customers currently may receive
only sales service while the smaller of the large volume industrial customers may also elect the same.

Intermountain provides both interstate and distribution transport services to its industrial customers in its
service territory through the use of its pipeline contracts and/or distribution system. For Intermountain’s firm
T-1 and T-2 customers, the customer’s gas is received at the NWP mainline, transported on the Company’s
interstate capacity and distribution system and then redelivered to the customers’ facilities. The Company
also transports gas for customers only on its distribution system. Under its T-4 tariff where the customer
delivers supply to one of Intermountain’s applicable citygates and that supply is then redelivered on a firm
basis to the customer’s facilities via the Company’s distribution facilities. The Company also has a T-3 tariff
which provides for interruptible distribution on the distribution system.

Intermountain has actively managed the utilization of its transport capacity through the growth years of the
1990’s as projects to build new capacity have largely been either extremely expensive or unavailable to this
area requiring the Company to consider several alternatives. In fact, NWP has no current plans for facilities
expansion that would provide additional rights to Intermountain. One strategy to forestall the need to
purchases new capacity has been to encourage the Company’s industrial customers to participate in the
open market to procure their own capacity. The Company has also limited growth in the industrial customer’s
loads under firm agreements and has required new transporters to elect T-4 firm distribution-only
transportation service. These strategies have allowed the Company to continue to serve the growing core
market while minimizing the need for new pipeline capacity. Intermountain recognizes that growth will
eventually dictate the need for additional capacity and consistently evaluates the need for capacity additions.

The Company has one main transmission line in Eastern Idaho that serves customers in the Idaho Falls
region. Due to increased customer load in this area, this line has been capacity constrained at times and is
one of the resources that the Company monitors closely. Intermountain has also recently identified two other
locales that are projected to see capacity constraints in the coming years without capacity additions. The first
is the Sun Valley lateral in Central Idaho and the Canyon County area in Western Idaho. All three of these
constraint areas and potential solutions to the constraints are addressed in this study.
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Storage Resources

General. Storage facilities have been developed to bride the gap between demand and supply in peak
periods. This gap occurs because the demand curve is not linear, the supply curve somewhat linear and
transport capacity is very linear. Storage helps to balance supply requirements with demand needs while
minimizing cost.

To illustrate, Intermountain’s load shape is very steep in the winter months and peak demand greatly exceeds
maximum transport capacity. This is because it would be prohibitively expensive to obtain enough capacity to
supply that last unit of demand that only exists on the peak day(s). Storage facilities are utilized to fill this gap
as gas is injected into storage during off-peak periods and then withdrawn during the peak load months. The
advantage is two-fold: first, the Company can shave the winter peak off the Demand Curve therefore
minimizing transport capacity needs and secondly, injecting gas in off-peak months provides a more efficient
year-round utilization of both gas supply and the interstate capacity resource. Additionally, the market often
prices off-peak supplies at a discount allowing the Company to better manage its portfolio and its overall
WACOG. Storage facilities are normally of two general types: liquefied storage and underground storage.

Liquefied Storage. Liquefied storage facilities make use of a process that pressurizes and supercools
gaseous methane to approximately minus 260 degrees Fahrenheit until it liquefies. Liquefied natural gas
("LNG") occupies only one-six hundredth the volume compared to its gaseous state and so it is an efficient
method for storing peak requirements. However, the liquefaction process is an expensive process and since
these facilities are of necessity man-made, the use of large steel tanks, safety equipment and costly
compression equipment is required. It typically requires as much as one unit used for liquefaction fuel for
every three to four units liquefied. Also, the full liquefaction cycle may take 5 – 6 months to complete.
Because of the high cost and length of time involved filling a typical LNG facility, it would normally be cycled
only once per year and its use reserved for peaking purposes.

However, the process of changing the liquid back into the gaseous state is an efficient process called
vaporization. Since the natural state of methane under typical atmospheric and temperature conditions is
gaseous and in fact, lighter than air, and the liquid methane is super-compressed, vaporization requires little
energy and will occur naturally under normal conditions. Vaporization of LNG into a system is usually
accomplished by utilizing the system pressure differentials through the opening and closing of valves. The
high pressure LNG is allowed to push itself into the lower pressure distribution system. Potential LNG daily
withdrawal rates are normally large and a typical withdrawal cycle may last less than 10 days at full rate. For
this reason, LNG is typically used as "needle" peaking supply and is usually located in market areas.

Intermountain utilizes two such facilities; one is NWP’s LS facility located near Plymouth, Washington and the
other resides on Intermountain’s distribution system near Nampa, Idaho. Neither facility requires the use of
existing transportation capacity as the Plymouth facility has bundled transport capacity for redelivery to
Intermountain and the LNG tank withdrawals go directly into the Company’s distribution system.

Underground Storage. This type of facility is typically found in naturally occurring underground reservoirs
(e.g. depleted gas formations, salt domes, etc.), aquifers or sometimes in man-made caverns or mine shafts.
These facilities often require little hardware compared to LNG and are usually less expensive to build per
equivalent volume. In addition, commodity costs of injections and withdrawals are usually minimal by
comparison. These lower costs allow the more frequent cycling of inventory; many such entities are utilized to
arbitrage changing market prices. Of more significance to Intermountain, the minimal commodity costs make
underground storage an ideal tool for winter baseload or for daily load balancing.

Another material difference for liquefied storage is the maximum level of injection and withdrawal. Because
underground storage involves far less compression as compared to LNG, daily injection levels are much
higher while daily withdrawal maximums are significantly less. Consequently, a typical withdrawal cycle might
last 35-60 days or more at maximum withdrawal. For this reason, the Company generally utilizes
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underground storage for winter baseload supply; the withdrawal cycle typically lasts from November to mid-
March.

Intermountain utilizes three underground storage facilities. The first is Jackson Prairie located near Chehalis,
WA and operated by NWP. Another is Questar’s Clay Basin facility Northeastern Utah that has a direct
connection to NWP. Lastly, the Company utilizes a facility located in Eastern Alberta called "AECO" operated
by the Encana. It is connected to the NOVA system and, unlike the other storage sites used by the Company
which are market-based, AECO is located near the producing fields of Alberta and does not require the use
of Intermountain’s interstate capacity to effectuate injections.

Below is a summary of Intermountain’s storage capabilities through 2009.

Intermountain Gas Company
Storage Capability Through 2009
Volumes in MMBtu

Facility
Maximum
Capacity
Withdrawal Cycle
Daily Max % of Peak
Injection Cycle
Daily Max Days
Redelivery
Capacity
LNG (Nampa) 580,000 60,000 17% 3,500 166 None
LS 770,520 72,000 21% 4,000 193 TF-2
SGS 1,092,099 15,000 4% 30,337 36 TF-2
Aeco 2,600,000 19,335 5% 26,000 100 TF-1
Clay Basin 5,857,500 48,809 14% 48,809 120 TF-1
Total 10,900,119 215,044 61% 112,646

Delivery Capacity. Both the Plymouth and Jackson Prairie facilities include distinct bundled firm redelivery
transport capacity on NWP equal to the daily the withdrawal rights. This enables Intermountain to withdraw
and redeliver these volumes without using its annualized firm capacity; however, injections do require the use
of interstate capacity. This is advantageous because having storage with its own redelivery capacity allows
the Company to minimize its purchase of its daily, or annualized capacity. Of course, this also minimizes the
unneeded capacity during the non-peak season.

AECO and Clay Basin are not bundled with transport redelivery capacity. This requires Intermountain to use
its already existing annualized capacity on NWP to move withdrawals to the Company's citygate locations. As
such, these facilities’ inventory is generally withdrawn in a winter baseload fashion. Clay Basin also requires
existing capacity for injections, while AECO does not. The LNG facility only requires capacity for injections
since it is located on the Company's own system; withdrawals generally occur via pressure differentials and
are reserved for the coldest peak periods. Notwithstanding the age of the LNG facility, it is considered to be
valuable from the peak demand perspective.

Summary. The Company generally utilizes its diverse storage assets to offset winter load requirements,
provide peak load protection and, to a lessor extent, for system balancing. Intermountain believes that the
geographic and operational diversity of the five facilities utilized offers the Company and its customers a level
of efficiency, economics and security not otherwise achievable. Geographic diversity provides security should
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pipeline capacity become constrained in one particular area. The lower commodity costs and flexibility of
underground storage allows the Company flexibility to determine its best use from alternatives such as winter
baseload, peak protection, price arbitrage or system balancing. Because of the high levels of daily withdrawal
capacity along with relatively high operating costs, the Company has traditionally used the liquefied inventory
facilities (LS and LNG) for needle peaking supply during periods of extreme cold.

Supply Resources Summary

Intermountain utilizes the most efficient mix of the above supply resources to provide reliable, secure, and
economic firm service to its customers. The Company is continually reviewing the varying needs of its
customer base as well as the changing environment in which it operates. Intermountain actively manages its
current mix of resources and is consistently seeking additional resources and techniques to maintain and
improve service to its customers. The Company actively monitors natural gas pricing and production trends in
order to maintain a secure reliable and price competitive portfolio. Intermountain also seeks innovative
techniques to manage its transportation and storage assets in order to provide both economic benefits to the
customers and operational efficiencies to its interstate and distribution assets.

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NON-TRADITIONAL RESOURCES

Non-traditional resources are defined here as providing additional resources to meet the design peak day
load by either decreasing the natural gas load using alternative fuels or increasing capacity within the existing
pipeline system. Five (5) such non-traditional resource alternatives were considered and are as follows:

· Fuel Oil
· Propane
· Propane-Air
· Portable LNG Facilities
· Compressor Station

A major contributor to the needle peak are the large volume industrial customers. Large volume industrial
customers typically purchase their own firm gas supply as well as interstate transportation to IGC’s delivery
points and then contract with IGC for firm transportation capacity within IGC’s local distribution system. By
incorporating the following alternative fuels, where applicable, the system demand needle peak can be
significantly reduced.

Fuel oil, propane, propane-air and the LNG facilities were evaluated as alternative fuels used in conjunction
with industrial customers during their peak day demand. This form of Demand Side Management in essence
reduces peak day demand within the distribution system as industrial customers switch to a particular
alternative fuel.

The addition of a compressor station increases the overall capacity of a pipeline system, but does not reduce
demand or load during peak usage.

Fuel Oil

Fuel oil is generally restricted to the industrial customers because of the equipment typically used within
industrial plants. Switching a boiler load over to oil and leaving the direct fire load on natural gas during peak
demand typically reduces the plant load by 50 - 70%. In some situations, some industrial customers have the
ability to switch entirely from natural gas to fuel oil. Burning fuel oil in lieu of natural gas does require
obtaining various permits from the local governing agencies and can be a lengthy process depending on the
specific type of fuel oil.

Capital costs for fuel oil facilities are approximately $150,000 - $250,000 providing 10,000 – 20,000 therms
per peak day up to eight (8) days. After the eight days, the facilities would then have to be refilled with oil at a
cost between $0.50 - $1.00 per gallon depending on contractual obligations and time of year. [Note: one
gallon of fuel oil is typically 138,000 – 155,000 BTUs, depending on grade and blending]. Fixed operation
and maintenance (O&M) costs are approximately $60,000-$120,000 per year.

Propane

Since propane is similar to natural gas, the conversion to propane is much easier than a conversion to fuel
oil. With the equipment, orifices and burners being similar to that of natural gas, an entire industrial customer
load (boiler and direct fire) may be switched to propane. Therefore, utilizing propane on peak demand could
reduce an industrial customers’ natural gas needs by 100%.

Capital costs for propane facilities are considerably higher than that for fuel oil. Typical capital costs for a
peak day send out of 30,000 therms per day are approximately $500,000 - $600,000. Such peak day send
out is limited to six days after which the facilities would have to be refilled with propane at a cost ranging from
$0.50 - $1.00 per gallon. [NOTE: One gallon of propane is approximately 92,000 BTUs]. Fixed O&M costs
are approximately $60,000 per year.

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Propane-Air

Propane-air facilities were evaluated with the potential of utilizing such facilities in both reducing the large
volume industrial customer load and providing additional supply to the core market load within the existing
distribution system.

Propane-air facilities used as an alternative fuel within industrial plants to reduce the peak is basically the
same as propane, with the exception of even higher capital costs. Such capital costs are approximately
$500,000 - $700,000 for the same peak day sendout of 30,000 therms with fixed O&M costs of approximately
$120,000 per year.

Using propane-air facilities to provide additional supply within the distribution system to meet the peak day
requirements was also evaluated. The same capital and O&M costs would be incurred as with an industrial
customer, but typically additional property and siting requirements would be required to locate the propane-air
facility near a distribution system. There are several interchangeability concerns brought about by too great a
concentration of propane-air when blended with natural gas, all of which can pose service, maintenance and
safety problems with unattended appliances.

Portable LNG Facilities

Portable LNG facilities are available for lease from various companies and could be used for peak shaving at
industrial plants or within a distribution system. Regulatory and environmental approvals are minimal
compared to permanent LNG plants and are dependent upon actual location of the portable LNG facilities.
The available delivery pressure from LNG equipment ranges from 50 psig to 350 psig with a peak day
sendout of approximately 24,000 th/day per vaporizer.

Fixed costs with one vaporizer and two days of storage, regardless of any LNG usage, is approximately
$150,000 - $250,000 for a three-month period. The actual cost of LNG is dependent upon usage, natural gas
prices, liquefaction and transportation costs. The cost of LNG trucked to Idaho during the winter months is
estimated at $0.80 - $1.20 per therm.

Compressor Stations

Compressor stations are typically installed on pipelines or laterals operating at higher pressures with a fairly
significant gas flow. IGC currently has only two such pipelines of which the installation of a compressor
station would be practical – the Sun Valley Lateral and the Idaho Falls Lateral. Regulatory and environmental
approvals would be significant while engineering and construction costs for a compressor station capable of
providing a 100,000-200,000 therm per day capacity increase is approximately $2,000,000 - $3,000,000.
Fixed O&M costs are approximately $100,000 - $150,000 per year.
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DISTRIBUTION SYSTEM MODELING

Gas flow through a pipe falls under the engineering discipline of fluid mechanics. Due to the nature of fluid
flow, there is a finite amount of gas that can flow through a pipe of a certain size and length. Engineers in the
field of gas distribution can use the laws of fluid mechanics to approximate flow conditions of gas through
pipes. Ultimately, it is total throughput or system capacity that is desired to be known during peak demand.

Gas distribution networks, or systems, rely on pressure differentials to move gas from one place to another.
If the pressure is exactly the same on both ends of a particular system, gas will not flow. When gas is
removed from some point on a system (i.e. regulator station, house meter, industrial customer) to get to an
appliance or boiler, the pressure in the system at that point is then lower than the pressure upstream in the
system. This pressure differential causes gas to move from the higher pressure point to the point of removal
in order to equalize the pressure throughout the system. The same principle keeps gas moving from the
interstate transmission lines to the local distribution company's distribution system to the residential meters
and ultimately to the appliances inside the homes. Therefore, it is important that gas engineers design a
distribution system in which the beginning pressure (from regulator stations) within the system is high enough
so that a feasible and practical pressure differential is created when gas leaves the system.

When the total load exceeds the system capacity, the pressure at the far end of the system becomes zero
and the system basically runs out of pressure. Using the laws of fluid mechanics, engineers determine the
maximum flow of gas through a distribution system of various pipe diameters and lengths that will not cause
significant pressure drops. This process is known as "distribution system modeling."

The modeling process is important because it allows the engineer to determine the capacity of various
distribution systems. For example, if a large usage customer were added to a distribution system, the
engineer must evaluate the existing system and then determine whether or not there was adequate capacity
to maintain the new customer along with the existing customers. Modeling is also important when planning
new distribution systems. The correct size of pipes must be installed to allow for the flow needed to meet the
requirements of current customers and reasonably anticipated future customers. Also, existing system
capacities can be evaluated using the model by gradually increasing the loads throughout the system until
the pressure loss within the system becomes unacceptable.

Modeling by Town

In December, 1992, IGC purchased a gas network analysis software program from Stoner Associates
allowing the engineer to model all sizes of distribution systems. The software program was chosen for its
reliability, versatility and power. Using the software, individual models are created for each of IGC's various
distribution systems, including high pressure laterals, intermediate pressure systems and distribution system
networks.

The model of the various systems is constructed as a group of nodes and elements. A node is defined in a
system as being a point where gas either enters or leaves the system, change in pipe diameter or the
connection of pipe. An example of a node in a distribution system might be a number of homes within a
subdivision, a small commercial load, or a large industrial load. An element is defined in a system as the
various sizes of pipe, regulator stations or compressor stations, which make up a distribution system. A
model for a small sized town typically consists of approximately 100 - 300 nodes and 250 elements, a
medium size town typically consists of 500 - 1500 nodes and 1200 elements and a large city or area typically
consists of 4,000 or more nodes and 4,000 or more elements.

The software program allows the engineer to input and/or change the gas load at an individual node, some or
all nodes. By using the forecasted loads within this integrated resource plan, IGC engineers can determine
anticipated future constraint areas based on the calculated pressure drops. When constraint areas are
found, the engineer determines the most practical and cost effective method of solving the problem.
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Sometimes the solution is as simple as increasing pressure within the system, but in most situations
additional pipe or looping is required. Looping scenarios can then be modeled to determine the ultimate size
and location of pipe in order to maintain adequate pressures throughout the system.

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PROMOTING THE EFFICIENT USE OF NATURAL GAS

Natural Gas and our National Energy Picture

In the United States, natural gas currently meets 24% of the nation’s energy needs, heating 52% of American
homes, and providing needed energy to manufacturing plants, commercial businesses, and most new electric
power plants. Demand for this highly efficient fuel is expected to grow by 45% by 2015.

Natural gas is the cleanest and most efficient fossil fuel. Continued expansion of natural gas usage can help
address several environmental concerns simultaneously, including smog, acid rain, and greenhouse
emissions.

Furthermore, 99% of the natural gas used in the United States comes from North America, where supplies
are abundant. And the 2-million-mile underground natural gas delivery system has an outstanding safety
record, and is reliably capable of delivering natural gas, regardless of the weather.

Natural Gas Equipment Efficiency

Technology has given us many new and more efficient ways to meet our energy needs without sacrificing the
environment. Over the recent years, new natural gas residential and commercial HVAC equipment and
appliances have become far more efficient as Federal and State equipment efficiency standards have taken
effect. And in the existing customer group, as older, less-efficient equipment wears out, it’s replaced with
these newer, more efficient units. Thus, the entire natural gas user base grows more efficient each year.

The adoption of more energy efficient building codes and standards – new homes and commercial structures
built to higher standards driven by Federal and State codes, has meant far more efficient use of natural gas.
And as with the replacement of older equipment mentioned above, older housing and commercial units are
being upgraded to higher efficiency standards. Most people don’t realize it, but the average household uses
22% less natural gas than it did in 1980, thanks largely to the aforementioned efficiency improvements. And
by using energy wisely, consumers will continue to use less, and therefore help control their energy costs.

The Gas Technology Institute continues to perform important ongoing research and development work in the
gas equipment arena, from residential to large industrial. GTI is not just developing new uses for natural gas,
but also improving the efficiency and cleanliness of existing applications. IGC has participated in local GTI
research and development projects, and will continue that collaboration as the opportunities arise.

Natural gas equipment efficiency makes economic sense in today’s new energy era, and IGC will continue to
encourage new residential and commercial technologies, as they become available.
Natural Gas Conservation Customer Education

On our website, www.intgas.com, customers can obtain detailed information regarding energy conservation
at home or their business. Also at the website, customers can view our Energy Conservation Brochure,
which was mailed to all our +240,000 core-market customers in October 2003. The web version of this
brochure contains a link to the Idaho Department of Water Resources Energy Division. IDWR offers low-
interest loans for energy efficiency upgrades, including space and water heating equipment, insulation, and
duct sealing. The Energy Conservation Brochure in hard copy is also available at all of our customer contact
offices throughout the IGC service territory.
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In addition to bill paying and other services, IGC customers can also access their individual billing and gas
consumption history on the website. Customers can enroll online or by phone. The process is easy, and
access is immediate. IGC customer communications, mass-media advertising, website, and marketing
information all encourage customers to consider high-efficiency equipment when making their equipment
purchase or upgrade decisions. We recently completed a 30-second TV commercial wherein our company
spokesman, Jerry Kramer, offers a variety of energy saving advice measures, including automatic setback
thermostats. This commercial also promotes the intgas.com website as a source of conservation information.
This conservation video message is available for viewing on our website.

We have recently added a detailed 10-minute conservation tips video to our website. This video was
produced by the Alliance to Save Energy and our AGA partner, Washington Gas. It gives a wide variety of
energy saving instruction and advice, including do-it-yourself installation of insulation, storm windows, and
weather-stripping, as well as how-to’s for natural gas conservation measures and practices. Customers will
be able to view the entire video, or select segments that deal with particular conservation-minded tasks and
instructions. Intermountain will show this video during our IRP public meetings, and will conduct additional
conservation seminars to highlight this presentation. Wherever possible, our communications messages
promote the use of our website for such information. A DVD copy of the video is contained in Exhibit No. 6.

Intermountain’s customer contact and marketing personnel are equipped to assist current and potential
customers with evaluating the advantages of installing high-efficiency gas equipment where possible.

Intermountain will promote high-efficiency gas furnaces through our involvement in the 2005 Parades of
Homes around our service territory. Sponsorship assistance will be focused on those builders whose Parade
homes have a 90% efficient natural gas furnace. We hope to collaborate with the Northwest Energy
Efficiency Alliance Energy Star promotion of high-efficiency furnaces in the Pacific Northwest beginning
sometime in 2004.

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2005 - 2009 Integrated Resource Plan

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Intermountain has a long history of promoting the efficient use of natural gas by our customers. Over the
years, IGC has offered rebates and incentives for the installation of energy saving devices such as pilotless
furnace ignition systems, furnace flue dampers, and still to this day, a high-efficiency (90%) furnace
conversion rebate.

Our website also promotes the IGC Gas Equipment Finance Program. Wells Fargo Bank is the lender in this
program. This program provides current and prospective customers an equipment-financing avenue that
includes competitive rates and an expedited approval process. It’s another financing avenue that enables
consumers to replace older equipment with new, higher-efficiency units, and other energy saving measures,
such as energy-efficient windows, and insulation upgrades.

IGC remains a partner in the Rebuild Idaho energy efficiency campaign targeted toward our state, municipal
and county entities, our school districts, and our institutions of higher education. IGC is an active voice in
Idaho’s legislative process as the lawmakers consider new, higher-efficiency building and energy codes.

Energy Efficiency Through The Direct Use of Natural Gas

Another, bigger-picture aspect of efficient natural gas usage is the concept of direct use, whenever possible.
“Direct use” refers to employing natural gas at the user point for space heat, water heating, and other
applications, as opposed to using natural gas to generate electricity to be transmitted to the user point and
then employed for space or water heating.

As hydroelectric generating capacity becomes more constrained in the Pacific Northwest, additional
generating capacity either under construction or planned will primarily be natural gas fired. Direct use will
mitigate the need for future generating capacity. If more homes and businesses use natural gas for heating
and commercial applications, then fewer new generating plants will be needed. And at times of excess
capacity, water storage normally used for generating power, can be released for additional irrigating, fish
migration, and navigation uses.

Natural gas fired combustion turbines are generally 60 – 65% efficient at best. Further- more transmission
and distribution losses can total another 5 – 10%. Effectively, half of the energy originally contained in the
natural gas has been lost before arriving at the point of use. High-efficiency natural gas furnaces are rated at
96% efficiency. New 2004 gas water heater efficiency standards provide for 67% efficiency. So from a
resource and environmental basis, direct use makes the most sense. More energy is delivered using the
same amount of natural gas. Thus, lower cost and lower CO2 emissions spread out over a far wider airshed.
This direct, and therefore, more-efficient natural gas usage will serve to keep natural gas prices, as well as
electricity prices, lower in the future. Our success in marketing to Idaho’s residential new construction
market, where we have nearly a 100% penetration rate along our service mains, is a prime of example the
direct use of natural gas, where possible.

Natural Gas and Avoided Electrical Generation and Transmission

To illustrate the significant role that IGC plays in southern Idaho’s total energy picture, IGC has over 218,000
residential customers. The average annual therm usage of an IGC space-heating-only customer is 608
therms. That equates to a total residential therm usage of 132,544,000 therms in a year. If the total was
used at the Federal efficiency minimum of 78%, then (132,544,000 X .78 = 103,384,320 therms X 100,000
btu’s/therm) or 10,338,432,000,000 btu’s were generated. (A therm is 100,000 btu’s of heat.) There are
3,412 btu’s in a kilowatt-hour. At 100% resistance heat efficiency, this means that the IGC residential space-
heat customers would use the equivalent of (10,338,432,000,000 / 3,412) or 3,030,021,102 kilowatt-hours to
heat their homes. This is the same as 3,030,021 megawatt hours of power saved, year in, year out.
According to their website, Idaho Power’s total annual residential megawatt hour sales for 2002 were
4,447,155. Were the aforementioned 218,000 IGC residential customer using electric space heat, Idaho
Power’s total residential sendout would rise to 7,477,176 mWh, a 68% increase.
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In peak terms, if these 218,000 IGC customers had electric furnaces with 25kw capacity, and just 1/3 of them
were operating simultaneously during a cold-weather winter peak, there would be an additional winter peak
load of 1,817 megawatts. Again, according to their website, the Idaho Power Winter 2002 peak load was
2,131 megawatts. Without the direct use of natural gas to heat these 218,000 homes, Idaho Power’s winter
peak load could reach 3,948 megawatts, an 85% increase! This additional 1,817 megawatt peak load would
be the equivalent of over seven 250 megawatt natural gas-fired electric generating facilities all running at full
throttle. This would probably also require a substantial increase in transmission facilities to handle this peak
load, since it would be well above the Idaho Power Summer 2002 peak of 2,963 megawatts.
In terms of recently-shed electric load, just since 1991, IGC has converted over 25,000 residential electric
heating customers to natural gas. Using the space heating consumption rates shown above, these gas
conversions save about 347,000 megawatt hours of residential sendout per year. In winter peak terms, using
the “1/3 operating simultaneously” example in the paragraph above, 208 megawatts of peak load is saved.
This “year in, year out” electrical conservation is realized at no cost to the electric customers in Southern
Idaho. IGC’s television advertising and other efforts promote direct use by actively targeting the conversion
market. All of the sendout and peak savings illustrations above consider only residential space heating. If
residential natural water heating were included, the annual sendout figures would rise by at least 25%.

In terms of summer energy consumption, IGC residential water heaters also provide some relief to the ever-
growing hot weather electric demand. IGC has over 160,000 RS-2 (space and water heat) customers. If,
instead these were 160,000 electric water heaters each rated at 9,000 watts, or 9kW, this would amount to
1,440 megawatts of total load. If this total amount was treated as shifted or curtailed, per the recently
approved Utah Power and Light irrigation load control credit rider, the credit value would range from
$1,382,400 in September to $3,225,600 for July. But the summer water heating load curtailment and shifting
provided by the IGC water heater customers comes at no cost to electric utilities or their customers.

Enhancing Our Industrial Customers Efficient Use of Natural Gas

Intermountain Gas Company has recently developed and employed technology enhancements which allow
our industrial customers the ability to access their natural gas usage data "real-time" in a secure manner via
the Internet. Industrial customers processes can be energy intensive. Through the use of these technology
enhancements, Intermountain has facilitated a more accurate and real-time correlation between an industrial
customer's energy consumption and plant production thereby increasing our industrial customer's ability to
develop and establish energy efficiency gains. Intermountain has entered into a "trial period" with selected
customers, whereby these selected customers are being asked to use the technology and provide feedback
regarding the same. This feedback will be evaluated for potential future enhancements to the program.
Intermountain expects that during late 2004, this technology will be offered to all those industrial customers
that currently provide natural gas usage input into Intermountain's Supervisory Control and Data Acquisition
("SCADA") system.

Conclusion

Ever-increasing and more pervasive energy standards and practices will continue to improve the energy
efficiency of Intermountain Gas Company’s customers. Intermountain will continue in its active role
promoting the wise and efficient use of natural gas. The wise, direct use of natural gas in the coming years
will help keep overall energy costs down in southern Idaho, and will ensure ample, lower-cost electricity for its
many other valuable uses.
Intermountain Gas Company
2005 - 2009 Integrated Resource Plan

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RESOURCE OPTIMIZATION

Introduction

The IRP model is an optimization model that selects resources over a pre-determined planning horizon to
meet forecasted loads by minimizing the present value of fixed and variable resource costs. The model
evaluates and selects least cost supply and transportation resources utilizing a standard mathematical
technique called linear programming.

This summary will first describe the model structure and its assumptions in general. Initial results will then be
discussed.

Components of the Model

The IRP model has three basic components:

· Demand forecast (See Exhibit No. 5, Appendix A)
· Supply resources (See Exhibit No. 5, Appendix B)
· Transportation resources (See Exhibit No. 5, Appendix C)

Underlying these three components is a structure of supply sources, transport capacity (arcs) and demand
areas (nodes) which mirror how the IGC system contractually operates (see below). In any IRP model, there
must be a balance between modeling in sufficient detail to capture all major economic impacts while at the
same time, simplifying the system so that the model operates efficiently and the results are understandable.
For an IRP model such as IGC's, where major supply and transport additions are being evaluated over a 5
year period, only major elements need to be recognized. This is in distinction to a dispatch model which
needs to balance precisely requiring detail more fully representative of the system requirements. For this
reason, a simplified structure is utilized in this IRP model.

Model Structure

The following table and graphic presents the demand and supply nodes and transport arcs of the IRP model.

Area # 1 2 3 4 5 6 7 8 9
Name Sumas Stanfield Boise Idaho Falls N. Green S. Green NIT Sun Valley Canyon

Sumas
Stanfield
IMG
Canyon Sun Valley Idaho Falls
N. Green
S. Green
Boise/All Other
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Demand Areas and Forecast

Four demand areas, or nodes, are designated: Canyon County, Sun Valley, Idaho Falls and Boise/All Other.
Idaho Falls, Canyon County and Sun Valley reflect all loads served off those specific “laterals” and are
separated in order to facilitate the evaluation of distribution capacity enhancements for those laterals.
Boise/All other represents all loads outside of those demand nodes.

The model utilizes a peak-to-low load duration curve ("LDC") to represent the demand forecast. The graphic
below depicts a sample LDC for the total system. This type of LDC summarizes load information from
highest to lowest daily usage. The LDC approach is utilized for an IRP rather than a chronological approach
to capture the general forecasting problem of planning for peak, shoulder and base demand in distinction to
short term or daily dispatching. Design weather and projected customers are used to model forecast load
requirements.

To simplify modeling, the LDC is aggregated into periods with similar load characteristics, to represent load
changes over the entire year with a minimum of data points. (See Exhibit No. 5, Tale 5.1) The bold horizontal
lines in the figure below provide an example of the aggregation periods utilized in the model. The model
actually utilizes four separate LDCs so as to separately represent the Boise/All Other, Sun Valley, Canyon
County, and Idaho Falls demand characteristics. The model assumes that IGC must provide gas supply,
interstate and distribution transportation for core customers and only transportation for T-1 and T-2
customers. The T-4 customer's usage is only included for the distribution system.

Load Duration Design Base FY03
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
mm
b
t
u

Supply Resources

Resource options for the model are of two types: storage resources and supply contracts; all are utilized in a
similar manner. All resources have beginning and ending years of availability and they also have an annual
flow capability and a peak day capability. They can be assigned both variable and fixed costs. Additionally,
information relating to storage resources includes injection period, injection rate, fuel losses and other
storage related parameters are included.

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Each resource must be designated to a delivery area. One advantage of certain storage facilities is that no
additional mainline transport is required since the resource is either sited within a demand area node or is
bundled with its own redelivery transport capacity. Resources can be delivered into the IGC (or “IMG”)
system from Alberta (Nova Inventory Transfer or "NIT"), Sumas, Stanfield, North of Green River, or South of
Green River, utilizing the appropriate transport arcs. Additionally, IGC system storage can be directly applied
to the LDC for any demand node.

Transport Resources

Transport resources can be contracts for capacity such as those with Northwest Pipeline (NWP) or National
Gas Transmission ("NGT"), or for distribution mainlines such as the Idaho Falls lateral. Transport resources
are explicitly associated with arcs in the model, which are usually contracts between supply and demand
areas. For example, supply resources to be delivered from Sumas to Idaho Falls, first must use the Sumas
to the IMG arc and then form IMG to Idaho Falls arc. The system representation generally recognizes NWP's
postage stamp pricing and capacity release.

Transport resources have a peak day capability, which is assumed to be available year round, unless
otherwise noted. Transport resources can have different cost and capabilities assigned them as well as
different years of availability. For example, different looping options for the Idaho Falls lateral are available to
the model at different periods to facilitate timing decisions.

Model Operation

The selection of a best cost mix of resources, or resource optimization, is based on the cost availability and
capability of the available resources as compared to the projected loads. The model chooses the mix of
resources which best meet the optimization goal of minimizing the present value cost of delivering gas supply
to meet customer demand. Both the fixed and variable costs of transport, storage and supply are included.
The model will exclude resources it deems too expensive.

The model can treat fixed costs as sunk costs for certain resources. If a fixed cost or annual cost is entered
for a resource, the model will include that cost for the resource in the selection process that will influence its
inclusion vis-à-vis other available resources. If certain resources are committed to and the associated fixed
cost will be paid in any event, only the variable cost of that resource is considered during the selection
process. However, any "new" resources, which would be additional to the resource mix, will be evaluated
using both fixed and variable cost.

The model operates in a PC environment. Inputs and outputs are in a spreadsheet format. The optimization
is preformed by PC linear programming software.

Once the model computes the best resource mix, it writes the results to spreadsheet files, which are then
organized by a set of macros in a summary spreadsheet.

Special Constraints

As stated earlier, the model minimized cost while satisfying demand and operational constraints. Several
constraints specific to IGC's system were modeled in the IRP model.

· LNG, SGS, and LS storage either does not require redelivery transport capacity or has its own
transportation for withdrawal; transportation utilization of this capacity must match storage withdrawal
from these facilities.

· The T-1 and T-2 customers' transportation requirements are met utilizing IGC transport capacity but no
supply resources are provided.
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· The T-4 customer transportation requirements utilize only Intermountain's distribution capacity.

· Resources to the lateral nodes (e.g. such as Idaho Falls) must be transported first to IMG, and then from
IMG to the lateral.

Model Results

The IRP optimization model for the five-year study, FY05 through FY09, is presented and discussed below.
The results of the model are summarized, by demand scenario, by four types of tables:

· Resource Utilization Table
· Transport Utilization Table
· Storage Injection Table
· Annual Cost Summary

To refer to these tables please see: Baseline: See Exhibit No. 5, Appendix D; High Growth: See Exhibit No.
5, Appendix E; Low Growth Scenario: See Exhibit No. 6, Appendix F:

Each of these tables will be discussed as well as the results for years 1 and 5. The changes in model results
between year 1 and year 5 will be summarized. The results for years 2 through 4 are available for review as
part of the applicable appendix, but these tables will not be discussed.

Resource Utilization - General

The Resource Utilization Table (See Exhibit No. 5, Appendix D) provides usage information on supply and
resources available to IGC. Column 1 corresponds to the resource number. Column 2 corresponds to a
resource acronym, which the model utilizes for printouts. The next two columns identify the arc to which the
resources are delivered to NWP (or upstream arc where applicable). For example, the Sum-A resource is
delivered to NWP at Sumas.

The utilization rates are the most important data determined by the model. These rates specify the percent of
capability that the model determines are optimal for resources in each period. The utilization rate by period
for a resource multiplied by the resources capability on an MMBtu per day basis adjusted for a loss factor
results in the daily capacity of that resource that is utilized by period, columns 13 through 18. The total
column represents the simple sum of the daily capacities utilized. Note that total gas flow utilized per period
is the capacity utilized per day times the number of days in a period and is contained in other detail tables.

There are generally three types of supply resources; existing supply contracts, existing storage contracts and
incremental/spot contracts. Transport resources include both NWP capacity and upstream NGT capacity (to
bring Alberta supply to NWP at Stanfield) as well as the capacities for the three laterals on the Intermountain
system. The following sections will summarize the utilization of each type of supply and transport resource
for the model years 1 and 5.

The model selects the best cost portfolio based on relative variable cost pricing. However, it also has been
designed to comply with operational and contractual constraints that exist in the real world (i.e. if the most
inexpensive supply is located as Sumas, the model can only take as much as can be transported from that
point). It should also be noted here that in order for the results to provide a reasonable representation of
actual operations, all existing resources that have committed cost contracts are assigned as must run
resources. Other resources are evaluated by variable cost.

Another important assumption regarding "Fill" supply is that it is treated as an economic commodity meaning
that its availability is dynamic. The model can select available Fill supply at any node, for any period and in
any volume that it needs up to capacity constraints. To ensure that the model provides results that mirror
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reality, these supplies have been aggregated into “Peak”, “Winter” and “Summer” price periods. Each
aggregated group has a different relative price with the Peak price the highest and the summer the lowest.
Additionally, since term pricing is now normally based on the monthly spot index price through the utilization
of futures, price swaps or other derivative products, no attempt has been made to develop fixed pricing for
incremental term contracts (see Exhibit No. 5, Tables 5.2 and 5.3 for pricing data).

The transportation utilization table provides the same type of information for transportation resources and is
shown in a similar format as the resource utilization table. Each transportation resource has a resource
number and acronym. In addition, the receipt ("from") and delivery ("to") points associated with each
transport arc are listed in columns 3 and 4. Columns 5-10 show the transportation utilization rate output from
the model and represent the percent of total resource available that the model utilizes by period. These
utilization rates multiplied by the transport capability determine the daily transport capacity utilized by period
as shown in columns 13-18.

Again, the incremental transportation "Fill" contracts are being treated as "commodity" resources in that the
model can utilize this capacity in the period it needs it, but in somewhat limited volumes. The current
assumption of on-demand incremental transport is likely not "real-world" since it would generally only be
readily available on demand in the summer. But, selection of this type of resource in a peak or winter period
would generally indicate the need for a term contract of some nature.

Transportation resources fall into four categories: existing, Lateral capacity, storage, and incremental
resources. The existing resources are labeled ES (NWP) or PGT. Lateral expansions demonstrate the need
for their implementation by the change in utilization rates over time.

The storage injection table provides the amount of resources injected into the various storage facilities. Just
as storage may only be withdrawn in the peak and winter periods, injections may only occur in winter,
reflecting the actual withdrawal cycle in the winter and the injection cycle in the summer. The injection rate
multiplied by the injection MMBTU and the loss factor results in the net MMBTU injected by period.

Summary Results – Baseline – Year 1

Supply.

The existing supply resources contracts 1 - 11, respectively, have utilization rates of 1.0 (or 100%) for all
available periods meaning that these resources are utilized at maximum capacity in all demand periods. This
is due to contractual take obligations.

Storage facilities are fully withdrawn over Peak periods. In some instances, annual usage is less than full
annual capability, but annual minimum withdrawals are achieved. There are a number of factors affecting
shoulder usage such as cost, withdrawal capability, and transportation capacity. As loads continue to grow,
further utilization of these facilities can be expected.

Resources labeled as T1&T2-"xx" represent the non-core customer load resources. These resources are
included to ensure that year-round interstate transportation capacity is available for the non-core, firm
transportation customers. The resources labeled as T-3 and T-4 represents the distribution system CD in
order to ensure that distribution capacity is available for this transport load.

The remaining resources are general supply resources that are tied to Nymex Futures hub spot prices, which
are used to fill in relative needs in various periods. These resources are selected by the model only after
existing contract supplies are utilized, due to pricing or contractual constraints.

Storage Injections. As described above, injections may only occur in the summer period and after factoring
in fuel losses, total injections match the withdrawals in the other periods for each facility. Although the
storage cycle can overlap years (e.g. injections could actually occur in a subsequent year) in the real world,
the nature of this model has resulted in a closed system: net injections must equal net withdrawals.
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Transportation. Given the need for incremental interstate capacity as highlighted the Company’s previous
IRP filing, Intermountain secured additional capacity. 250,000 therms of new capacity are available by the
beginning of year 1 and another 150,000 therms/day will come on by year 5. The model indicates that
Intermountain has sufficient interstate capacity to serve the required needs through 2009.

Annual Cost Summary. Exhibit 5, Appendix D summarizes the dollar cost of the resources selected by the
model, show the cost of supply resources utilized, reflects the transportation costs as determined by the
model, and lists a grand total of all resource costs and calculates a net present value cost for comparative
purposes.

Summary Results - Year 5

Supply. By the fifth year, the utilization of supply resources has changed somewhat to respond to load
growth. Supply resources 1 through 11, are still utilized at full capacity when available. The model is
selecting approximately 60,000 MMBtu of incremental/spot supply during peak periods to fill the growing
loads.

Storage Injections. Storage is fully utilized, both on an annual and peak day basis. Injections in year 5 are
higher than in year 1 due to the increase change in storage withdrawals and still occur in period 6 for all 5
storage facilities. The selection of a “Citygate” supply resource suggest the Company may want to investigate
further needle peaking supply or other peaking resource by year 5.

Transportation. As before, the Company has sufficient interstate capacity year around. Two lateral
expansions have been selected on the Idaho Falls lateral, while both Sun Valley and Canyon County have
utilized lateral expansions as well.