201009012010 IRP.pdf

EXECUTIVE OFFICES
INTERMOUNTAIN GAS COMPANY RECEIVED
555 SOUTH COLE ROAD. P.O. BOX 7608. BOISE,IDAHO 83707. (208) 377-600 . FAX: [phone]
18fDiAUG 31 PH 3=1¡9
August 31,2010 IDAHO PU,-:"¡~-~ .
UTIUTIES COM~éíSSION
Jean Jewell
Commission Secretary
Idaho Public Utilities Commission
472 West Washington St.
P. O. Box 83720
Boise,ID 83720-0074
RE: Intermountain Gas Company's 2010 Integrated Resource Plan
Case No. INT-G-10-04
Dear Ms. Jewell:
Attached for filing with the Idaho Public Utilties Commission are the original and seven
copies of Intermountain Gas Company's 2010 Integrated Resource Plan.
If there are any questions regarding the attached, please contact me at [phone].
Very truly yours,
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Katherine J. Barnard
Manager
Gas Supply and Regulatory Affairs
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2011 - 2015 Integrated Resource Plan
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AUGUST 2010
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
INTERMOUNTAIN GAS COMPANY
INTEGRATED RESOURCE PLAN
2011-2015
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Table of Contents
EXECUTIVE SUMMARY ................................................................................................................................. 5
DEMAND FORECAST OVERVIEW .............................................................................................................. 14
HEATING DEGREE DAYS AND DESIGN WEATHER................................................................................29
USAGE PER CUSTOMER ............................................................................................................................33
INDUSTRIAL USAGE FORECAST ...............................................................................................................40
LOAD DURATION CURVES .........................................................................................................................45
TRADITIONAL SUPPLY-SIDE RESOURCES.............................................................................................. 51
NON-TRADITIONAL SUPPLY RESOURCES ..............................................................................................61
AVAILABLE AND POTENTIAL SYSTEM CAPACIT ENHANCEMENTS ................................................65
DISTRIBUTION SYSTEM MODELING ......................................................................................................... 67
THE EFFICIENT AND DIRECT USE OF NATURAL GAS ........................................................................... 69
INTERMOUNTAIN GAS DEMAND-SIDE MANAGEMENT PROCESS........................................................ 76
RESOURCE OPTIMIZATION ........................................................................................................................ 80
COMPARATIVE ANALYSIS 2010 IRP VS. 2008 IRP ................................................................................. 88
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Table of Exhibits
Appendix A: John Church Economic Forecast
Appendix B: Intermountain Gas Market Penetration rates
Appendix C: Intermountain Gas Market Conversion Rates
Appendix D: Base Case - New Customers, Adjustments & Total Customer
Forecast
Appendix E: High Case - New Customers, Adjustments & Total Customer
Forecast
Appendix F: Low Case - New Customers, Adjustments & Total Customer
Forecast
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Exhibit NO.2
Appendix A: Regression Data - Therms and Degree-Days
Appendix B: Regression Statistics
Exhibit NO.3
Appendix A: Total Company Design Weather - Base Price/Growth LDC Data
Appendix B: Idaho Falls Lateral Design Weather - Base Price/Growth LDC Data
Appendix C: Canyon County Area Design Weather - Base Price/Growth LDC
Data
Appendix D: Sun Valley Lateral Design Weather - Base Price/Growth LDC Data
Appendix E: State Street Lateral Design Weather - Base Price/Growth LDC Data
Exhibit NO.4
Maps 1 - 3: Western North America - Natural Gas Basins, Pipelines and Storage
Projects
Charts 1 - 6: Natural Gas Deliveries, Production, Index Prices and Basin Price
Forecasts
Load Duration Curve Inputs
Supply Resource Inputs
Transportation Capacity Resource Inputs
Supply Resource Pricing Inputs
2011 Optimization Model Results
2012 Optimization Model Results
2013 Optimization Model Results
2014 Optimization Model Results
2015 Optimization Model Results
Table 1:
Table 2:
Table 3:
Table 4:
Table 5.1:
Table 5.2:
Table 5.3:
Table 5.4:
Table 5.5:
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Exhibit NO.5
Appendix A: Boise Public Workshop Announcement & Agenda
Appendix B: Pocatello Public Workshop Announcement & Agenda
Appendix C: Boise/Pocatello Workshop Presentation
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Executive Summary
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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, comfortable form of heating energy.
Intermountain Gas Company ("lntermountain"f'IGC") 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 Page 69). 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 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.
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nU Backdrop
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 the first half of 2009, Intermountain served an average of 305,309 customers in 74
communities through a system of over 10,000 miles of transmission, distribution and service lines. Over
120 miles of distribution and 2,883 service lines were added during 2009 to accommodate new customer
additions and maintain service for Intermountain's growing customer base.
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The economy of Intermountain's service area is based primarily on agriculture and related industries.
Major crops are potatoes and sugar beets. Major agricultural-related industries include food processing
and production of chemical fertilzers. Other significant industries are electronics, general manufacturing
and services and tourism.
Intermountain provides natural gas sales and service to two major markets: the residentiaVcommercial
market and the industrial market. During 2009, an average of 275,522 residential and 29,673 commercial
customers used natural gas primarily for space and water heating, compared to an average of 272,657
residential and 29,263 commercial customers in 2008. This equates to an increase in average residential
and commercial customers of 1.1 %.
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Intermountain's industrial customers transport natural gas through Intermountain's system to be used for
boiler and manufacturing applications. Industrial demand for natural gas is strongly influenced by the
agricultural economy and the price of alternative fuels. Forty-one point two percent (41.2%) of the
throughput on Intermountain's system during 2009 was attributable to industrial sales and transportation.
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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.
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
The customer growth forecase was created and analyzed from both a total company perspective and 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 certain regions of Intermountain's service
territory, 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, the State Street Lateral Region and
the All Other Region.
Peak day sendout studies and load duration curves were developed under design weather conditions
(see page 29) to determine the magnitude and timing of future deficiencies in firm peak day delivery
capabilties from both a total company interstate mainline perspective, as well as geographic region
specific perspectives, Residential, commercial and industrial customer peak day send out was matched
against available resources to determine which combination of new resources would be needed to meet
Intermountain's future peak day delivery requirements in the most cost effective manner.
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 1.75% under the
base case scenario. 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
(Volume in Them)
NWFirm Peak Day Sendout Incrementa Peak Day Sendout
Transport Core Industal Core Industral
Capacity ~Firm CD Tota Market FirmCD1 Total
FYll 2,751,270 3,599,903 190,010 3,789,913
FY12 2,743,760 3,652,007 190,010 3,842,017 52,104 0 52,104
FY13 2,736,250 3,718,077 190,010 3,908,087 66,070 0 66,070
FY14 2,728,240 3,801,171 190,010 3,991,181 83,094 0 83,094
FY15 2,699,590 3,882,776 190,010 4,072,786 81,605 0 81,605
i Future growth in trnsport CD is IißUte to T -4, which does not afect Inteountan's interstate pipeline capacity reuirements.
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:
Intermountain's existing firm delivery capabilty on the peak day is made up of the resources shown on
the following page:
1 Multiple residential and commercial customer growth scenarios were developed. Each scenario
("baseline", "high" and "low") was driven by the potential for varying outcomes of Idaho's economy (See
Pages x-x.)
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
PEAK DAY FIRM DELIVERY CAPABILITY
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(Volumes in Decatherms)il FY12 FY13 FY14 FY15
Maximum Daily
Storage Withdrawals:
Nampa LNG 580,000 580,000 580,000 580,000 580,000
Plymouth LS 1,096,235 1,096,235 1,096,235 1,096,235 1,096,235
Jackson Prairie 30,337 30,337 30,337 30,337 30,337
SGS
Total 1,706,572 1,706,572 1,706,572 1,706,572 1,706,572
Storage
Maximum 2,751,270 2,748,770 2,751,270 2,743,760 2,736,250
Deliverabilty (NWP)
Total Peak Day 4457842 4455.342 4,4S7 842 4450.332 4442.822
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(Volumes in Therms)
FY11 FY12 FY13 il Em
Peak Day Deficit'0 0 0 0 0
Total Winter Deficit 0 0 0 0 0
Days Requiring Additional 0 0 0 0 0
Resources
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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 formulating the best plan to meet the projected deficits in the various regions within
Intermountain's service territory (see "Non-Traditional Resource Options" - Page 61). Additionally, each
region is analyzed within the framework of the Company's Distribution System Model (See Page 67).
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Idaho Falls Lateral Region
The Idaho Falls Lateral ("IFL") is 1 04 miles in length and serves a number of cities between Pocatello in
the south and St. Anthony in the north (See Map on Page 13). The customers served by 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 15% of the total company
customers and 19% of the company's total winter sendout during December of 2009.
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
When forecasted peak day sendout on the IFL is matched against the existing peak day distribution
capacity (810,000 therms), a peak day delivery deficit occurs during 2011 and increases at levels shown
on the following tables:
LOAD DURATION CURVE. IDAHO FALLS DESIGN BASE CASE
(Volumes in Therrs)Existing
Distribution Peak Day Sendout Incremental Peak Day Sendout
Transport Core Industrial Core Industrial
Capacity Market Firm COl Total Market Firm CO2 Total
FY11 810,000 657,874 221,750 879,624
FY12 810,000 668,933 221,750 890,683 11,059 0 11,059
FY13 810,000 685,566 221,750 907,316 16,633 0 16,633
FY14 810,000 703,123 221,750 924,873 17,557 0 17,557
FY15 810,000 716,620 221,750 924,873 13,497 0 13,497
1 Existing firm contract demand includes T -4 and T -5 requirements.
2Future growt 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 Therm)
FY11 FY12 FY13
Peak Day Deficit 1 69,620 80,680 97,320
Total Winter Deficif!93,090 123,350 178,490
Days Requinng Additional Capacity 2 3 3
FY14
114,870
240,800
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FY15
128,370
281,460
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1Equal to the total winter sendout in excess of distribution capacity.
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 traditionl intersate capacity to deliver inventory to the citygate.
The industrial customer base on the IFL is unique in that a few of these customers have the potential and
abilty 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 mitigated by working
with these customers to facilitate the use of fuel oil at these customer's facilties. Additionally, with the
addition of the Rexburg LNG facilty, these deficits can easily be mitigated by bringing gas on from the
facilty. However, the projected delivery deficits are of such magnitude that "looping" of the existing
system is warranted adding the necessary firm delivery capabilty 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
December of 2009.
When forecasted peak daysendout on the SVL is matched against the existing peak day distribution
capacity (175,000 therms), a peak day delivery deficit occurs during 2011 and increases at the levels
shown on the following tables:
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
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LOAD DURATION 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 CO2 Total
FY11 175,000 173,957 8,150 182,107
FY12 175,000 174,868 8,150 184,422 911 °911
FY13 175,000 176,554 8,150 184,704 1,686 °1,686
FY14 175,000 178,846 8,150 192,187 2,292 °2,292
FY15 175,000 181,053 8,150 189,203 2,207 °2,207
lExisting finn coct demand includes T -4 and T-5 requirements.
2Future growt in transport CD is limited to T-4 which only impact Intennountan's distribution capacity requirements.
FIRM DELIVERY DEFICIT - SUN VALLEY DESIGN BASE CASE
(Volumes in Therms)
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Peak Day Deficit 1 7,110 8,020 9,700
Total Winter Deficit 9,710 13,260 17,790
Days Requiring Additional Capacity 2 2 3
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12,000
24,570
FY15
14,200
30,220
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1Equal to the total winter sendout in excess of distribution capacity.
2Equal to the total winter sendout in excess of interstate capacity less total "peaking" storage. Peaking storage does not
require the use of Intennountain's traditional interstate capacity to deliver inventory to the citygate.
As can be seen from the above table, growth along the SVL wil warrant a future 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 capabilty 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 capabilty and ultimate capacity on the SVL
using a series of cost effective system upgrades, beginning in 2011 with a planned compressor station
which wil add additional capacity, removing any peak deficits through 2015. In addition, to better
manage this additional capacity, the company received approval to provide incremental snowmelt loads
on an interruptible only basis, which wil help to offset demand during peak day loads.
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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 13% of the company's total winter sendout during
December 2009.
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
When forecasted CCL peak day design sendout is matched against the existing peak day distribution
capacity (700,000 therms), there are no peak day delivery deficits occurs during the 2011-2015 planning
years as shown on the following tables:
LOAD DURTION CURVE. CANYON COUNTY DESIGN BASE CASE
(Volumes in Then)
Existng
Distribution Peak Day Sendout Incrementa Peak Day Sendout
Transport Core Industral Core Industrial
Capacity M!Firm CD! Tota Market FirmCDz Tota
FYll 690,00 514,776 100,100 614,876
FY12 690,000 530,677 100,100 630,677 15,901 0 15,901
FY13 690,00 544,680 100,100 64,780 14,003 0 14,003
FY14 690,000 561,428 100,100 661,528 16,748 0 16,748
FY15 690,000 578,274 100,100 678,374 16,846 0 16,846
IExisting fi contract demand includes T -4, and T-5 reuirements.
2Puture grwt in trsport CD is limited to T -4 which only impacts Inteunta's distrbution capaity reuirments.
FIR DELIVERY DEFICIT - CANYON COUNTY DESIGN BASE CASE
(Volumes in Therms)
Peak Day Deficitl
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Total Winter Deficir o o o o o
Days Requinng Additional Capacity o o o o o
¡Equal to the tota winter sendout in excess of distrbution capacity.2Equal to the tota winter sendout in excess of interstate capaity less tota "peng" storage. Peang storage doe not reuire the use of
Intermountan's traditional interstate capacity to deliver inventory to the citygate.
While diverse in nature, the industrial customer base served by the CCL does not currently have the
capabilty to switch to alternative fuels as a means of mitigating peak day sendout and Intermountain is
currently exploring optional means of enhancing the distribution capabilty on this LateraL.
State Street Lateral
The State Street Lateral makes its first appearance in this IRP, and there is currently no threat of capacity
constraint. However, it is an area that Intermountain is watching, and wil continue to watch as demand is
beginning to approach design capacity. During the 2011-2015 time frame, there are no capacity
constraints as shown on the following tables:
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
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LOAD DURATION CURVE - STATE STREET DESIGN BASE CASE
(Volumes in Therms)
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Existing
Distbution Peak Day Sendout Incrmenta Peak Day Sendout
Transport Core Industrial Core Indusal
Capacity Market Firm CD! Total ~FirmCD2 I!
FYll 585,00 511,270 17,100 528,370
FY12 585,00 514,66 17,100 531,766 3,396 0 3,396
FY13 585,00 519,276 17,100 536,376 4,610 0 4,610
FY14 585,00 526,531 17,100 543,631 7,255 0 7,255
FY1S 585,00 534,459 17,100 551,559 7,928 0 7,928
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¡Exsting fi contrt demand include T-4, and T-5 reuirments.2Future grwt in trport CD is limite to T -4 whch only impats Interounta's distrbution capacity reuirments.
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FIR DELIVERY DEFICIT - STATE STREET DESIGN BASE CASE
(Volumes in Therm)
~ 1 Pea Day Deficitl
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Days Requiring Additional Capacity o o o o o
¡Equal to the tota winte sendout in excess of distbution capacity.2Equal to the tota wintr sendout in excess of interstate capacity less total "peng" storage. Peang storage do not reuire th use of
Intermountan's tritional intetate capaity to deliver inventory to the citygate.
Assessment of Potential DSM Programs
1
In addition to reviewing traditional and non-traditional resource alternatives, the company has also
analyzed potential DSM (Demand Side Management) measures as a solution for potential constraint
areas. The company continued to utilze information from the Navigant Study to develop potential DSM
programs to be included in the resource optimization modeL. For planning purposes, the company
focused on programs that would not duplicate other programs, would not be redundant with regard to
codes or other regulations, and would provide truly additional energy savings. Cost-effectiveness was
important, but the measures selected had to impact the greatest number of customers, and their most
significant gas usage.
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analyzed the continuation of its $200 rebate to customers that install a 90%-or-greater efficiency natural
gas furnace at the time of conversion. The company also evaluated offering a $30 rebate when a
customer installs a .64 or greater energy factor (EF) gas water heater at the time of conversion. The
The company also evaluated expanding its conversion equipment rebate program to existing customers
who replace a lower efficiency furnace with a 90%-or-greater efficiency natural gas furnace and evaluated
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
offering the proposed water-heater rebates to those customers who replaces a .59-or-below EF natural
gas water heater with a .64-or-greater EF natural gas unit.
The additional programs - water heater conversions, and the furnace/water heater upgrades would be
deployed in a pilot program on the Idaho Falls lateral in Calendar 2011. Our advertising promotion of
high-efficiency new homes and ENERGY STAR is ongoing.
Summary
Residential, commercial and industrial customer growth and its consequent impact on Intermountain's
distribution system were analyzed using design weather conditions under various scenarios for Idaho's
economy. Peak day sendout under each of these customer growth scenarios was 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 needed to meet these
projected deficits were analyzed within a framework of options, both traditional and non~traditional,
including DSM measures, to help determine the most cost-effective means available to manage the
potential deficits. In utilzing these options, Intermountain's Core market and firm transportation customers
can continue to rely on uninterrupted firm service both now and in the years to come.
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DEMAND FORECAT OVERVIEW
The first step in resource planning is forecasting future load requirements. Three essential components
of the load forecast include projecting the number of customers requiring service, forecasting the weather
sensitive customers' response to temperatures and estimating the weather those customers may
experience. To complete the demand forecast, load projections of non-weather sensitive customers are
also included.
Intermountain's long range demand forecast incorporates various factors including divergent customer
forecasts, statistically based gas usage per customer calculations, varied weather profies and banded
natural gas price projections (all of which are fully discussed further in this document). Using various
combinations of these factors results in eighteen separate and diverse demand forecast scenarios for the
weather sensitive Core market customers.
Combining those projections with the largely non-weather sensitive industrial market forecast provides
Intermountain with eighteen total company demand scenarios that envelop a wide range of potential
outcomes. These forecasts not only project monthly and annual loads but also predict daily usage
including peak demand events. The forecast is further refined by the development and inclusion of base,
high and low gas price forecasts and customer growth scenarios. The inclusion of all of this detail allows
Intermountain to evaluate the adequacy of its supply arrangements under a wide range of demand
scenarios. The next several sections outline the methodology used to build the demand forecast for this
IRP.
This section of the Plan describes and summarizes the residential and commercial customer growth
forecast for the years 2011 through 2015. This forecast provides the anticipated magnitude and direction
of IGC's residential and small customer growth by IGC Distribution System Segments for the company's
current service territory. Customer growth continues to be the primary driving factor in the company's
five-year demand forecast contained within the IRP.
The Segments are as follows:
· The Canyon County Segment, which consists of the Core Ma.rket 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, Bonnevile,
Fremont, Jefferson, and Madison Counties, along with approximately 35% of the Core Market
Customers in Pocatello, Bannock County.
· The "North of State Street" Lateral Segment, ("State Street") consisting of the area of Ada County
north of the Boise River, bound on the west by Kingsbury Road west of Star, and bound on the east
by State Highway 21. This segment is newly-defined and included in this 2010 IRP.
· The All Other Customers Segment, consisting of the Core Market Customers in Ada County not
included in the "North of State Street" segment, Bear Lake, Caribou, Cassia, Elmore, Gem,
Gooding, Jerome, Minidoka, Owyhee, Payette, Power, Twin Falls, and Washington Counties.
Additionally, 65% 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 is based on three (3) key components:
· Residential New Construction Customers
· Residential Customers who convert to natural gas from an alternative fuel
. Small Commercial Customers
14
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
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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 2009 Economic Forecast for
the State of Idaho by John S. Church (Church Forecast or Outlook), dated September 2009. Using the
assumption that a new household means a new dwellng 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.
Although the new State Street segment contains a small portion of Canyon County in addition to the
major portion entirely in Ada County, an additional estimate was made for that segment after the total Ada
County forecast was derived. Using the 2005 COMPASS growth forecast for Ada County, the forecast
growth in the Traffic Analysis Zones (T AZ) in the State Street segment was compared to the overall
forecast growth for all of Ada County. This was calculated to be 27%. This was used as the base for
estimating the forecast growth in the State Street segment.
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.
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With the continued downturn in the housing market, IGC growth projections are down considerably, when
compared to the 2008 IRP. The Church Forecast household numbers are employed to determine the
relative overall number of customer additions, as well as the distribution of those customer additions, that
is, the location of additional customers within our system. The following graph depicts the relationship or
"shape" of incremental customer additions by segment.
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IRP BASE CAS INCREMENTAL CUSTOMER GROWTH BY SEGMENT
_,GO
40600
4,GO
i3,50 l DFY113,GO DFV12
2,50 _FY13
DFY14
2,GO .FY15
1,500 r-
1 ,GO ..
ndj~150I::
~-I::0
CANYON SUNYALEY IDAHO FALLS STATE STREET ALL OTHER
15
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
The Church Forecast provides three economic scenarios: base case, low growth, and high growth.
Intermountain 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.
Annual Additional Customers
Residential and Small Commercial
12,00
8,00
_High Growth..SaseCase
..LowGrowth
10,000
6,000
4,00
FY11 FY12 FY13 FY14 FY15
The following table summarizes 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
Rangeasa %Average as a %Rangeasa %Average as a %
Of Base Case of Base Case Of Base Case of Base Case
Low Growth 99%-100%99%88%-93%91%
Baseline 100% -100%100%100% -100%100%
Hiah Growth 100%-101%101%111% -117%114%
Range Range
(2011 - 2015)Average (2011 - 2015)Average
Low Growth 314,241 - 340,412 326,n2 5,660 -7,760 6,603
Baseline 314,657 - 344,069 328,665 6,100 - 8,800 7,260
High Growth 315,334 - 349,229 331,365 6,760 -10,290 8,288
As mentioned earlier, the economic downturn, and its resulting negative impact on housing and business
growth has resulted in a much reduced IGC customer growth forecast in the years common to the 2008
and 2010 IRP's. The following graph provides a comparison of the customer additions forecasted under
base case conditions,
16
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Ann u a I Add ltio n a I C u s to me rs II
Residential and Sm all Com m erelal
2010 IR P VS. 2008 IR P
12,000
l...i........
....,-.
r:.',"10,000 A
_20101RP
_20081RP8,000
6,000
-
rn...'.'~.....'.......
~:,.,
:~~4,000
FY 11 FY12 FY13
Vl..,.....'.'.,....
tt~J 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.
HOUSEHOLD PROJECTIONS I CHURCH FORECAST
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The September 2009 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 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 reconcilation.
As previously mentioned, the Church Forecast provides three scenarios: (1) baseline, (2) high growth,
and (3) low growth. The baseline 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,
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The Base Case Economic Growth Scenarios
The September 2009 Economic Forecast for the State of Idaho and its 44 counties is for a weaker
economic outlook than that contemplated in the Summer 2007 Forecast. Along with a slowdown in
housing and overall construction, Idaho's economy is expected to post significantly reduced employment
17
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
growth through the forecast period. This is in stark contrast to a growth rate earlier this decade that was
at least twice the national average rate, and at times, close to three times that of the nation as a whole.
The manufacturing industries in Idaho, which were the hardest hit in the national recession of 2001, had
stil not regained employment to pre-recession levels by the end of 2007. The prospects for future
manufacturing job gains have softened even further in the September 2009 Outlook from those projected
in the Summer 2007 Outlook. In particular, Idaho's natural resource-related manufacturing industries,
and its high-tech manufacturing industries are deemed to be troubled through most of this economic
outlook.
Idaho's manufacturing sector had been the State's engine of growth throughout the 1990s. With the
onset of the 2001 national recession and the subsequent manufacturing job losses, by 2005, Idaho had
shed nearly 9,500 manufacturing jobs from its August 2000 pre-recession peak, when the manufacturing
sector employed nearly 77,000 statewide. Similarly, the natural resource industries of logging and mining
also experienced severe employment cutbacks dunng the last recession which, in total, reduced the
industry's employment in Idaho by nearly 10% during the 2001 to 2005 period.
And, despite an unprecedented level of housing demand in the nation during 2005, Idaho's lumber and
wood products industries did not even exhibit a glimmer of renewed life in spite of the overwhelming
demand for lumber products. Add to that a serious downturn in the prices for computer memory chips,
and two of Idaho's larger manufacturing industries that one would have expected to be a continuing
source of economic strength throughout the current decade have faltered badly. Idaho's mining industry
did show some renewed strength with the temporary rise in precious metals prices which occurred a few
years ago.
During the current national economic slowdown, and the concurrent slowdown in the Idaho economy,
state government in Idaho has experienced a sharp drop in income and sales tax collections. Faced with
the prospect of annual operating budget deficits, the state has found it necessary to not only cut
spending, but to curtail employment. State government employment in Idaho, which, in the few years
prior to the current downturn showed positive employment gains, has weathered layoffs and wage
freezes.
In 2009, Idaho's economy posted an overall loss in nonagricultural employment of 4.3%, about 28,300
jobs. Not surprisingly, construction employment in Idaho dropped significantly in 2009, with 8,000 jobs
lost, or 19.9% below the 2008 leveL. The first hits were in the residential realm, with Idaho's 2006
slowdown in residential housing construction. Reduced commercial and infrastructure construction activity
in the following couple years made for the job losses in that sector.
Other major statewide sectors losing jobs during 2009 were Manufacturing, with nearly 6,000 jobs or 10%
lost during 2009; and Trade, with a loss of 7,000 positions, or 6.4% of the 2008 total. The only non-
agricultural job category which showed any positive change during 2009 was Educational and Health
services, which grew by 3,700 jobs or 4.6% during the year. And while the aforementioned job reductions
have been felt everywhere in Idaho, the Treasure Valley endured over 50% of the employment losses
that the State experienced from December 2008 to December 2009.
In the September 2009 Economic Forecast, nonagricultural employment in Idaho is projected to be nearly
4.4% lower by the year 2030 than the level projected in the 2007 Forecast.
Manufacturing employment does not fare so well in the September 2009 Outlook, slipping 5.1 % below the
levels forecasted in the Summer 2007 Outlook by the year 2015, and dropping by 4.4% by the year 2030.
Projections of the future population growth in Idaho weaken in the September 2009 Outlook compared to
the Summer 2007 version, Idaho's total population is forecasted to grow from the estimated 2010 figure
of 1,566,260 to 2,192,470 millon by 2030, an annual growth rate of 1.7%, Incidentally, this projected
2030 population figure is 3.9% below the 2030 population level anticipated in the Summer 2007 Outlook.
The number of future households projected in the State is similarly lower in the 2009 Outlook.
18
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(Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
The High and Low Economic Growth Scenarios
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The High Growth and Low Growth Scenarios of the September 2009 Economic Forecast present
alternative views of the economic future of Idaho and its forty-four counties. The High Growth Scenario of
the Economic Forecast presents a long-term vision of a more- rapidly growing economy in Idaho. For
example, the High Growth Scenario produces a projected statewide population of nearly 2,539,500 in the
year 2030 versus a Base Scenario Idaho population forecast of 2,192,470 in the same year. The High
Growth scenario presents an absolute population gain of nearly 917,000 over Idaho's estimated 2010
population of 1,622,400, and an annual average compound rate of population growth of 2.3% per year.
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Alternatively, the Low Growth Scenario of the September 2009 Economic Forecast does not present as
optimistic an economic outlook for the Idaho economy. In the Low Growth Scenario, Idaho's 2030
population is projected to reach the much lower level of 1,967,900. The Low Growth Scenario's projected
2030 population is 400,500 above Idaho's estimated 2010 population of 1,567,400, and represents an
annual average compound growth rate of population growth of 1.1 percent 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 exceeded the projected rates of growth in the High and Low Growth Scenarios of
the September 2009 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.
High Scenario Economic Forecast: Assumptions
\ J In the High Growth Scenario of the Summer 2009 Idaho Economic Forecast, it is assumed that the state
of Idaho continues to be an attractive environment for manufacturing firms. Therefore, in spite of the
employment losses that the State has experienced in this economic downturn, it is assumed that Idaho's
manufacturing industries regain some economic traction, and wil expand in the future. However, the
High Growth Scenario does not assume that the new growth in the manufacturing sector wil be the sole
driver of economic growth in the state. The greater number of manufacturing jobs in the High Growth
Scenario, when compared to the Base Case scenario, account for approximately 12.4 percent of the total
additional jobs projected in the High Growth scenario. The specific assumptions concerning the
manufacturing industries in the high growth scenario are:
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· The Food Processing industry regains strength, and increases employment. By the years 2010
and 2020 the High Scenario forecast projects that employment in the Food Processing industry
employment wil be nearly 400 jobs and 900 jobs, respectively, higher than in the Base Scenario
forecast. The High Growth Scenario forecast assumes that at least two additional food
processing plants (all dairy product processing plants and all located in South Central Idaho) wil
open during the 2010 - 2035 forecast period. It is also assumed that Idaho's traditional food
processing plants, which primarily process vegetable products, wil not fare well in any of the
projections of future scenarios. In the High Growth Scenario, it is projected that the traditional
vegetable processing plants wil only lose jobs at a slower rate than would be the projected case
in the Base and Low Growth Scenario forecasts. The projected employment gains in the food
processing industry are all expected to be in those plants processing dairy products. Those
plants are most likely to be located in the Magic Valley area of the State, and may be more likely
to be located at the periphery of the traditional concentration of the dairy industry in that area --
Le., on the eastern edge in either Cassia or Minidoka Counties, or in Elmore County on the
western side of the area.
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
· Employment in Idaho's Lumber and Wood Products manufacturing industry has slipped in the
current recession. In the High Growth Scenario, it is assumed that the lumber and wood products
industry in the state only recovers to prerecession levels in the forecast period. Most of those
jobs wil be in wood product manufacturing - doors, windows, moldings, etc.
· Idaho's Electronics Industry rebounds in the High Case Scenario, with the projected opening of a
new production plant in the Boise MSA. This plant is projected to be roughly equivalent in size to
AMI's facilty in Pocatello, and is expected to employ approximately 1,500 people by the year
2010, and 2,500 by the 2020. In the Base Case Scenario it is projected that other, already
existing electronics industry manufacturers in Idaho are expected to add nearly 2,500 jobs over
the 2010 to 2035 forecast period, with other new-to- Idaho manufacturers adding nearly 3.500
new jobs in the 2010 to 2035 forecast period. As a result, the High Growth Scenario does not
produce a much higher level of employment that that found in the Base Case Forecast
· Idaho's employment in Stone, Clay, and Glass Products, and Fabricated Metal Products
manufacturing is projected to be nearly 8.0% greater in the High Case Scenario than in the Base
Case Scenario by the year 2010, and 6.0% and 8.0% higher than the Base Case by the years
2020 and 2030, respectively. This assumption is based upon an economic outlook that
anticipates a continuation of high levels of activity in the region's Construction Industry. This
assumption adds an additional 250 manufacturing jobs to the High Case Scenario.
· Transportation, Communications, and Utilties employment in the High Case Scenario is projected
to be nearly 9,300 jobs greater by the year 2030 than in the Base Case Scenario. The High Case
Scenario increases in Transportation Industry employment are expected to occur in Idaho's air
transportation sector. It is anticipated in the High Case Scenario that growth in air transportation
employment in Boise wil accelerate, and that a long-rumored regional air freight hub wil be
established at the Boise Air TerminaL. In addition, a new airport for the Wood River Valley wil be
put on a fast track. This new, larger, and safer, airport facilty wil attract increased air
transportation activity, not only directly to the Wood River Valley, but also indirectly with
connecting flights to Boise. In addition, the Communications and Utilties sectors are expected to
see higher levels of employment in the High Case Scenario. In both the Communications and
Utilties industries, a large portion of this projected increase in employment is in reaction to faster
population and household growth in the State of Idaho. However, another component of this
projected higher level of employment is the assumed continuation of the growth in the
Communications industrys "call center" facilties in Idaho (T-Mobile, and others), and the possible
establishment of five to ten large independent electric power production facilties, including wind
farms, in Idaho.
· Wholesale and Retail Trade industry employment in the High Case Scenario is projected to be
nearly 7,950 jobs (4.7%) jobs greater by the year 2010 than in the Base Case Economic
Forecast. This trend continues with the High Case Scenario projected to have nearly 14,700 and
18,700 more Wholesale and Retail trade jobs than the Base Case forecast by the years 2020 and
2030, respectively. This difference is largely due to the higher levels of population and
households projected in the High Case Scenario. It is also anticipated that most of this
Wholesale and Retail Trade employment would physically be located on the Snake River plain of
Southern Idaho near the population and household growth.
· Service industry employment in the High Case Scenario is projected to be even more robust than
in the already strong outlook found in the Base Case Scenario. In the High Case Scenario the
outlook for employment in the Service industries is projected to be nearly 3,900 jobs (2.0%)
greater than the Base Case outlook by the year 2010, and 8,500 jobs (12.0%) and 51,150 jobs
(15.0%) higher than the Base Case Scenario by the years 2020 and 2030, respectively. Again a
large portion of this difference is due to the higher levels of population and household growth
anticipated in the High Case Scenario. Hotel and motel accommodations and related activities
are also classified in the Service industry category. The High Scenario forecast assumes that
tourism-related or recreational travel in Idaho increases, and as a result, employment in the
lodging and recreation sectors also increases. In the High Scenario forecast, the Tamarack
20
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Resort is assumed to recover from its current financial troubles, and flourish under new
ownership.
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· The Service industry outlook in the High Case Scenario assumes that there is a portion, roughly
one-half, of the projected higher level of service industry employment that is caused by the
relocation of firms new to Idaho. The Federal Reserve Bank of San Francisco speculates that a
portion of the strong economic growth that is currently being experienced in Arizona, Nevada,
New Mexico, Oregon, Utah, and Idaho is due to an outmigration of population and businesses
from Califomia. Their studies have shown that many small California firms have come to the
realization that the cost of doing business in California has become too great for them to remain
competitive. Therefore, an increasing number of these firms are making decisions to relocate
close to, but outside of, California. Hence, the very rapid growth occurring in Nevada, Arizona,
and to a lesser extent Southern Oregon. Currently, New Mexico, Utah, and Idaho are capturing
only a small portion of that exodus. The High Case Scenario assumes that this trend continues,
and that Idaho, over time, captures a larger share of those relocation decisions.u
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· Federal Government employment in the High Case Scenario is projected to be nearly unchanged
from the Base Case Outlook by the year 2010, with only 600 jobs greater by the year 2020 and
thereafter. These increased Federal Government jobs are all assumed to be associated with
increased activity at INEL in Eastern Idaho. On the other hand, total Government employment in
the High Case Scenario is projected to be nearly 10,700 jobs higher (5.6%) than the Base Case
Scenario by the year 2020. This difference expands further to where Total Government
employment is 15,542 (9.9%) higher than the Base Case Scenario by the year 2030. Higher rates
of population and household growth in the High Case Scenario is the primary driving force behind
the projected greater employment numbers for Government employment.
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· By the year 2010 the High Case Scenario forecast of population and number of households in
Idaho is 4.3% higher the Base Case Forecasted figures. This represents nearly 66,145 more
people in the State by the year 2010 and nearly 28,500 additional households. The projected gap
between the High Case Scenario and the Base Case Scenarios widens by the years 2020 and
2030. In 2020 and 2030 the forecasted population of Idaho in the High Case Scenario is
projected to be nearly 259,250 and 347,000 more, respectively, than that predicted in the Base
Case Scenario. Similarly, the forecasted number of Idaho households in the High Case Scenario
is greater than the Base Case Forecast by 99,100 in the year 2020 and 133,560 more than the
Base Case in the year 2030.
Low Scenario Economic Forecast: Assumptions
In the Base Case Economic Forecast it is projected that Idaho wil gain nearly 11,500 manufacturing
industry jobs over the 2005 to 2035 period. In the Low Case Scenario Idaho continues to go in a direction
counter to the national trends for manufacturing employment and gains nearly 2,150 jobs over the period
2005 to 2035. However, this represents a much slower pace of growth -- 0.1 % per year over the period
2005 to 2035 -- than that projected in the Base Case Scenario forecast which is projected to increase at
an annual average rate of 0.5% per year over the period 2005 to 2035.
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· In the Low Case Scenario the State's loss of jobs in the Food Processing industry accelerates,
and nearly 3,200 additional jobs are lost over the period 2005 to 2035. The potato processing
plants in Southern Idaho would realize most of these job losses. It is assumed in the Low Case
Scenario that the JR Simplot plant in Caldwell would close with a loss of nearly 2,000 jobs. It is
anticipated that in the Low Case Scenario that the sugar processing plants in Southern Idaho
would also feel increased pressure from competition, and would find it necessary to close the
sugar processing plant in Nampa, Idaho, along with one of the other processing plants in Paul or
Twin Falls, Idaho. The dairy industry and its associated food processing plants would reach a
point where no further capacity could be added due to increased population and environmental
pressures.
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
· Employment losses in Idaho's Lumber and Wood Products manufacturing industry are assumed
to accelerate in the Low Case Scenario. In this scenario the brunt of these additional losses
would be felt in those portions of the wood products industry that could be increasingly vulnerable
to low-cost, foreign-produced products the Wood Grain Molding plants in Fruitland and Nampa,
Idaho.
· Idaho's Electronics Industry continues to add jobs over the period 2005 to 2035 in the Low Case
Scenario, but at a pace that is much slower than in the Base Case Scenario. The Base Case
Scenario projects that nearly 5,000 jobs wil be added in the Machinery and Electronics
manufacturing sectors over the period 2005 to 2035. The Low Case Scenario projects that only
2,000 additional jobs wil be added by the Machinery and Electronics manufacturing industries
over the period 2005 to 2035. No existing firms are assumed to close in this scenario. On the
contrary, the forecast can accommodate the addition of one or two small Electronics
manufacturing plants equivalent to AMI's Pocatello facility. In the Low Case Scenario the plant
being constructed in Pocatello to manufacture photovoltaic cells and panels is assumed to open
and operate for 5 years, and then close because of pressures from foreign competition in the
industry.
· Idaho's employment in Stone, Clay, and Glass Products and Fabricated Metal Products
manufacturing are both projeced to be at lower levels in the Low Case Scenario. This projection
is based upon an economic outlook that foresees lower levels of construction activity in the State.
In general, manufacturing employment in Idaho does not recover over the period 2005 - 2035 to
levels that were seen prior to this current recession.
· Transportation, Communications, and Utilties employment in the Low Case Scenario is projected
to have nearly 3,620 fewer jobs (a decline of 7.5%) by the year 2030 than in the Base Case
Scenario. It is assumed that the lower overall economic growth inherent in the Low Case
Scenario results in lower levels of demand for transportation. Also inherent in the Low Case
Scenario is the assumption that there wil be closure of some of the State's food processing
facilties which require large amounts of truck transportation
· Wholesale and Retail Trade industry employment in the Low Case Scenario is projected to be
nearly 1,740 jobs (1.0%) jobs lower than the Base Case Forecast in the year 2010. This trend
continues with the Low Case Scenario projected to have 6,450 and 8,200 fewer Wholesale and
Retail trade jobs in the years 2020 and 2030, respectively, than does the Base Case Forecast.
The difference is largely due to the lower levels of population and household growth found in the
Low Case Scenario. Nevertheless, the Wholesale and Retail Trade industry employment growth
represented in the Low Case Scenario averages 2.2% per year over the 2005 to 2035 period
· The forecasted Low Case Scenario employment in the Finance, Insurance, and Real Estate
sector falls 6.6%, approximately 2,160 jobs below the Base Case Forecast by the year 2020 and
slips further to 8.5% (3,200 jobs) below the Base Case by the year 2030. Again, the difference is
largely due to the lower levels of population and household growth found in the Low Case
Scenario.
· The Low Case Scenario assumes that employment growth in the Service sector wil slow to a
1.7% pace from the present to 2015, compared to the robust 3.7% rate that the State
experienced between 2000 and 2007. By the end of the forecast period, the year 2035, the Low
Case Scenario forecast of Service industry employment is nearly 51,150 jobs below (15.0%) the
Base Case Economic Outlook. The 1.7% pace of Service industry employment growth over the
period 2010 - 2035 in the Low Scenario is a reasonable, but not stellar pace, of growth.
· Future Government employment in the Low Case Scenario is projected to be 1,910 jobs (1,6%)
lower than the Base Case Scenario in the year 2010, and 12,450 jobs (9.2%) below the Base
Case in the year 2020. The differences expand further by the year 2030, with projected
Government employment in the Low Case Scenario being 15,540 lower (9.9%) than the Base
Case forecast.
22
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
. In the Low Case Scenario the forecasted population and number of households in Idaho is nearly
0.8% below the Base Case Scenario figures by the year 2010. This represents nearly 13,100
fewer people and nearly 6,620 fewer households in the State in the year 2010. The projected gap
between the Low Case Scenario and the Base Case Scenario widens further by the years 2020
and 2030. The projected Idaho population in the Low Case Scenario is nearly 127,560 and
224,520 less in the years 2020 and 2030, respectively, than that projected in the Base Case
Scenario. Similarly, the forecasted number of Idaho households in the Low Case Scenario is
lower than the Base Case Forecast by nearly 46,329 in the year 2020 and 82,305 less than the
Base Case in the year 2030.
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Fl The following graphs ilustrate 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.
f)
, I 510,000
1"1
.',.r 495,000
480,000
465,000
450,000
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il
435,000
420,000
~ANNUAL TOTAL HOUSEHOLDS FORECASTl
_HIGH GROWTH
~BASE CASE
_LOW GROWTH
FY11 FY12 FY14 FY15FY13
14,000
\ J
12,000
10,000
u
u
8,000
6,000
4,000
2,000
~A N N U A LAD 0 IT 10 N A L H 0 USE H 0 LOS FOR E CAS T I~--
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.-.-
--
_HIGH GROWTH
_BASE CASE
_LOW GROWTH
FY11 FY12 FY14 FY15FY13
The graphs on the following page provide comparisons of the growth in households forecasted under
base case conditions for the years common to the 2008 and 2010 IRP.
23
IA N N U A LAD 0 IT 10 N A L H 0 U S EH 0 LOS FO RECAST I2010 IRP VS 2008 IRP
12,000
10,000 '"~¿
8,000 _20101RP
_20081RP-
6,000
4,000
F Y 11 FY12 FY 13
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
ANNUAL TOTAL HOUSEHOLDS FORECAST
2008 IRP VS. 2010 IRP480,000
470,000
I
_20101RP_20081RP I
460,000
450,000
440,000
430,000
FY 11 FY 12 FY 13
Market Share Rates
IGC utilzes 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 Intermountain's additional residential new construction
customers to the total building permits in those regions. The forecast additional households, per the
Church Forecast, multiplied by the regional market penetration rate provide the anticipated residential
new construction customers.
Intermountain develops market penetration rates by way of the county construction reports that the
company's marketing and construction personnel use in prospecting for new construction customers.
The residential new construction sales in the specific areas covered by these reports are divided by the
total dwellings listed in the reports to derive the market penetration rate. The major population centers in
IGC's Service Territory are then grouped into three regions. For the Western region (Ada/Canyon
Counties) it is assumed that the rates wil remain relatively static through the forecast period since they
are already near 100%. However in the Central and Eastern regions, the forecast are forecasted to
increase due to anticipated gains in market share. The same set of market penetration rates was used in
24
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
the baseline, high growth, and low growth scenarios. The following table summarizes the market
penetration rates for the 2011 to 2015 period.
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FY11 mg FY13 fl FY15
Western Region 95%95%95%95%95%
Central Division 94%94%94%94%94%
Eastern Region 85%85%85%85%85%
MARKET PENETRATION RATES
The application of the above market penetration rates to the forecasted growth in households results in
the following estimated residential new construction growth under the three economic scenarios.
~ANNUAL RESIDENTIAL NEW CONSTRUCTION GROWTHl
10,000
('-)-
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-.IGH GROWTH
_ASE CASE
_LOW GROWTH
8,000
6,000
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4,000
FY 11 FY 12 FY13 FY14 FY 15
The following graph ilustrates the change in the residential new construction forecast under base case
conditions for the years common to the 2008 and 2010 plans.
ANNUAL RESIDENTIAL NEW CONSTRUCTION GROWTH
20081RP VS 2010 IRP
10,000
u
U
11
9,000
......
-
8.000 ~010 IRP
~008 IRP
7,000
6,000
5,000
4,000
FY 11 FY12 FY 13
25
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Conversions
The conversion market represents another source of customer growth for Intermountain. The company
acquires these customers when homeowners replace an electric, oil, coal, wood, or other alternate fuel
sourced 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. 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 wil be conversions.
REGIONAL CONVERSION RATES
FY11 FY12 FY13 FY14 EYWestern Region
Base Case 10%10%10%10%10%
High Growth 10%10%10%10%10%
Low Growth 10%10%10%10%10%
Central Region
Base Case 14%14%14%14%14%
High Growth 14%14%14%14%14%
Low Growth 14%14%14%14%14%
Eastern Division
Base Case 11%11%11%11%11%
High Growth 11%11%11%11%11%
Low Growth 11%11%11%11%11%
The following graphs ilustrate the relationship between the three economic scenarios for the annual
residential conversion growth forecast and provide a comparison to those the levels forecasted in the
20081RP.
~ANNUAL RESIDENTIAL CONVERSION GROWTHI
1,000
800
_HIGH GROWTH
..BASE CASE
_LOW GROWTH
600
400
FY11 FY12 FY13 FY14 FY15
26
r-1
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
ANNUAL RESIDENTIAL CONVERSION GROWTH20081RP VS 2010 IRP
700
rCi
650 ..*:&
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600
-:0101RP
""008 IR P
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550
500
FY 11 FY 12 FY 13
Small Commercial Customers
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Small commercial customer growth is forecast as a percentage of new construction customer additions
with the assumption that new households require additional new businesses to serve them. Since
household growth is the primary driver of the Company's residential growth, similarly household growth
drives small commercial customer growth. Based on the most recent three-year sales data, this ratio of
small commercial customer growth to residential growth has averaged 11.83%. Therefore, a company-
wide ratio of 12% was applied to the residential new construction forecasts to develop Base, High, and
Low Scenarios for the small commercial market.
The following graphs show the annual additional, as well as the annual total small commercial customers
for the period 2011 - 2015.
IANNUAL ADDITIONAL SMALL COMMERCIAL CUSTOMERS~
1,000
800
..HIG H GROWTH
..BASE CASE
..LOW GROWTH
j
J 600
j
400
J
FY11 FY12 FY13 FY14 FY15
27
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
ITOTAL ANNUAL 8M ALL COM M ERCIAL CUSTOM ERS I
33,000
_HIGH GROWTH
_BASE CASE
..LOW GROWTH
32,000
31,000
30,000
FY11 FY12 FY13 FY14 FY15
Similar to the comparisons in the residential sector, the following graph ilustrates the difference in the
annual small commercial customer growth forecasts between the 2008 IRP and the 2010 IRP for the
years~ommon to both studies:
ANNUAL ADDITIONAL SMALL COMMERCIAL CUSTOMERS
2010 IRP VS 200B IRP
1,000
..*..800
__20101RP
600
..20081RP
400
F V 11 FV12 FV13
28
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
n
HEATING DEGREE DAYS AND DESIGN WEATHER
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Intermountain's Integrated Resource Plan demand forecast captures the influence weather has on
system loads by utilzing Heating Degree Days (HOD's). HOD's are a measure of the coldness of the
weather based on the extent to which the daily mean temperature falls below a reference temperature
base. HOD values are inverse to temperature meaning that as temperatures decline, HOD's increase.
The standard HOD base - and the one Intermountain utilzes in its IRP - is 65°F (also called HDD65). As
an example, if one assumes a day where the mean outdoor temperature is 30°F, the resulting HDD65
would be 35 (i.e. 65°F base minus the 30°F mean temperature = 35 Heating Degree Days). Two distinct
groups of heating degree days are used in the development of the IRP: Normal Degree Days and Design
Degree Days.
¡'il;.:Customer Weighted Weather
n
Since Intermountain's service territory is composed of a diverse geographic area with differing weather
patterns and elevations, Intermountain uses weather data from seven NOAA weather stations located
throughout the communities served by Intermountain. This weather data is "weighted" by the customers
in each of the geographic weather districts to arrive at weighted weather for the Total Company. Several
distinct laterals and areas of interest are also addressed specifically by this IRP. Those regions are
assigned unique degree days as discussed in further detail below.
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Normal Degree-Days
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A Normal Degree Day is calculated based on historical data, and represents the weather that could
reasonably be expected to occur on a given day. The Normal Degree Day that Intermountain utilizes in
the IRP is computed based on weather data for the thirty years ended December 2009. For each day of
the year, the HDD65 for that day for each year of the thirty year period is averaged to come up with the
average HDD65 for the thirty year period for that day. This method is used for each day of the year to
arrive at Normal Degree Days for a year.
Design Degree-Days
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A Design Degree Day is an estimation of the coldest temperatures that can be expected to occur for a
given day. Design Degree Days are useful in estimating the highest level of customer demand that may
occur, particularly during extreme cold or "peak" weather events. For IRP load forecasting purposes,
Intermountain makes use of design weather assumptions (See table below: Design Degree-Days by
Month). Aggregating the daily HOD's over months and/or seasons allows Intermountain to construct
normal and design scenarios.
Design Weather Development1
Intermountain's design year is based on the premise that the coldest weather experienced for any month,
season or year wil occur again. The basis of a design year was determined by evaluating the weather
extremes over the last thirty years of heating degree data from NOAA (see the Degree Day Tables on
page 30). The review revealed Intermountain's coldest twelve consecutive months to be the fiscal year
1985 (October 1984 through September 1985). This year, with certain modifications discussed below,
represents the base year for design weather. These degree days reflect a set of temperature extremes
that have actually occurred in Intermountain's service area and would result in a maximum customer
usage response due to the high correlation between weather and customer usage,
Intermountain engaged the services of Dr. Russell Qualls, Idaho State Climatologist, to perform a review
of the methodology used by the company in calculating design weather and to provide suggestions that
may enhance design weather planning. One crucial area that Dr. Qualls was able to assist Intermountain
~..
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29
:_ i
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
in was in developing a method to calculate a peak day, as well as in designing the days surrounding the
peak day.
Peak Heating Degree Day Calculation
To develop the peak heating degree day, or coldest day of the design year, Dr. Qualls fited probabilty
distributions to thirt years of daily temperature data from seven weather station locations (Caldwell,
Boise, Hailey, Twin Falls, Pocatello, Idaho Falls and Rexburg). From these distnbutions he calculated
monthly and annual minimum daily average temperatures for each weather location, corresponding to
different values of exceedance probabilty. Two probabilty distributions were fitted, a Normal Distribution,
and a Pearson Type II (P3) distribution. Dr. Qualls suggested it is more appropriate for Intermountain to
use the P3 distribution as it is more conservative from a nsk reduction standpoint.
According to Dr. Qualls, "selecting design temperatures from the values generated by these probabilty
distributions is preferable over using the coldest observed daily average temperatures because
exceedance probabilties corresponding to values obtained from the probabilty distributions are known.
This enables the company to choose a design temperature, from among a range of values, which
corresponds to an exceedance probabilty that Intermountain considers appropriate for the intended use".
Intermountain used Dr. Qualls' exceedance probabilit data to review the data associated with both the
50 and 100 year probabilty events. After careful consideration of the data, Intermountain determined that
the company-wide 50 year probabilty event, which was an 81 degree day, would be appropriate to use
for the design weather modeL. For modeling purposes, this 81 degree day is assumed to occur on
January 15th.
Design Modification
A few adjustments were made to the base design year. First, since the coldest month of the last thirty
years was December 1985 (1638 HDD's), the weather profile for December 1985 replaced the January
1985 data in the base design year. For planning purposes, the aforementioned peak day event occurs on
January 15th.
To model the days surrounding the peak event, Dr. Qualls suggested calculating a 5-day moving average
of the temperatures for the thirty year period to select the 5 coldest consecutive days from the 30-year
period. December 1990 contained this cold data. The coldest day of December 1985 (the peak month)
was replaced with the 81 degree day peak day. Then, the day prior and three days following the peak
day, were replaced with the 4 cold days from the December 1990 cold weather event.
While taking a closer look at the heating degree days used for the Load Duration Curves (LDC's), it was
noticed that the design weather HDD's in some months were lower than the normal weather HDD's. This
occurred generally in the non-winter months, April through July. However, the Total Company and Idaho
Falls Lateral design HDD's had this same occurrence in November, although the differences were
minimal (1 to 3%). This occurred because, while FY 1985 was the coldest year on record and therefore
used as the base year for the design weather, the shoulder months were, in some cases, warmer than
normaL. Manipulating the shoulder and summer month design weather to make it colder would add
degree days to the already coldest year on record, creating an unnecessary layer of added degree days.
Therefore, Intermountain decided not to adjust the summer and shoulder months of the design year.
After design modifications were complete, the total design HDD curve assumed a bell shaped curve with
a peak at mid-January (see the Chart on the following page). This curve provides a robust projection of
the extreme temperatures that can occur in Intermountain's service territory.
30
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I
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
DESIGN DEGREE DAYS BY MONTH
HEATING DEGREE DAYS - NORMAU ACTUAL FY 85IDESIGN
65 DEGREE BASE
'1
Weighted Actual Design - Bell
Month Normal (30 yrs)Fiscal 1985 Shaped Curve
;1
October 44 605 606
November 826 834 833
December 1129 1350 1360
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Januar 1145 1512 1711
Februar 890 1196 1188
March 707 1026 976
0 April 466 435 427
May 269 236 241
June 80 69 71flJuly601.,August 11 35 43'........
September 140 288 317
Tota Year 6112 7586 7774
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Degree Day Graph
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1800
1600
1400
~ 1200
c 1000
~ 800C)
i! 600
400
200
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----.30 Year Weighted Normal
- Actual FY 1985
- - Design Weather
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Months
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31
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Area Specific Degree Days
In the 20081RP, Intermountain noted the unique characteristics of certain areas of its distribution system.
These are areas Intermountain carefully manages to ensure adequate delivery capabilties either due to a
unique geographic location, customer growth, or both. The areas Intermountain is currently monitoring
include the Idaho Falls Lateral, the Sun Valley Lateral, the State Street 12" Lateral, and the Canyon
County Area.
The temperatures in these areas can be quite different from each other and from the Total Company. For
example, the temperatures experienced in Idaho Falls or Sun Valley can be significantly different from
those experienced in Boise or Pocatello. Intermountain continues to work on improving its capabilty to
uniquely forecast loads for these distinct areas. A key driver to these area specific load forecasts is area
heating degree days.
Intermountain has developed Normal and Design Degree Days for the Idaho Falls Lateral, Sun Valley
Lateral, State Street 12" Lateral, and Canyon County Area. The methods employed to calculate the
Normal and Design Degree Days for each of these areas mirrors the methods used to calculate Total
Company Normal and Design Degree Days. Having distinct weather for these areas of interest allows
Intermountain to better forecast peak heating loads in areas of the system that have unique weather
characteristics, pipeline capacity issues, and population growth patterns.
32
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
USAGE PER CUSTOMER
This section of Intermountain's IRP discusses the calculation of therm usage per customer. These
results, when combined with the design degree days and customer forecast, are complete the
development of the IRP demand forecast.
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Because of the diferent usage characteristics associated with the peak-load winter months (November
through February) and the non-peak months (March through October), different modeling techniques
have been used for these two distinct seasons. In the winter months, the link between the weather and
customer usage is strongest, so a daily usage per customer equation is used. During the non-peak
months, an equation is used to predict monthly usage per customer and that usage is then converted to a
daily usage formula. The development and application of these formulas is discussed in greater detail in
the following sections.
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Customer Usage During Peak Months
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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. Because the relationship
between weather and usage is so strong during the winter months, it is possible to develop a daily usage
per customer equation. The following section discusses peak month model development.
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Variable Selection
Time Series
The first step in developing the regression equations was to determine the appropriate time period to
include in the study. Studies by the American Gas Association show that natural gas usage per customer
has decreased by about 1 percent per year for the past 38 years. This means the average U.S. home
using natural gas service is using one third less natural gas today than it did three decades ago.
Following the national efficiency trend, Intermountain has also noticed a decline in usage per customer in
its service territory. Some possible reasons for the decline in usage per customer include the Idaho
Residential Energy Code which' was adopted by many cities beginning in 1991. This new building
standard was designed to improve the energy effciency of new homes and commercial buildings. About
the same time, efficiency standards for furnaces and water heaters were improved. Additionally,
programmable thermostats are now installed routinely in new construction, and many people have
installed them in older homes as a way to reduce their energy expense (see "The Efficient and Direct Use
of Natural Gas", beginning at page 69).
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All of these conservation influences began impacting usage in the early 1990's. Since roughly 60% of
Intermountain's customers are new since 1990, the efficiency factors and building codes have had a
tremendous influence on our customer base. Rising energy prices have also heightened the customer's
interest in conservation. Higher energy prices in recent years have created an economic incentive for
people to use natural gas as efficiently as possible, creating downward pressure on our usage per
customer, and contributing to the structural changes we have seen in the data.
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To account for these structural shifts in the data, Intermountain used a time series beginning with the
winter of 1989/1990 through the winter of 2008/2009 to develop the regression equations.
d
Dependent Variable - Daily Usage Per Customer
Intermountain does not currently have technology that allows daily usage data to be collected by
customer class. As a result, total residential and small commercial market sendout for each day during
the peak months is used.
33
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Because this Core market group is non-homogeneous, Intermountain would like to test whether models
developed based upon the individual customer classes would perform better for predicting peak usage
per customer than models developed using total Core market data. Intermountain investigated options
that would enable the collection of daily usage data by Core market customer class. Current technology
requires the meters be read daily to collect daily data. This method of data collection is currently cost
prohibitive, and there is some concern that daily ERT interrogation would measurably shorten the life of
the units resulting in increased capital expenditures.
Market research tells us that new data collector ERT units are currently in the development stages.
These units would collect daily data. This data could then be downloaded as part of the normal monthly
meter reading process. Intermountain wil monitor this option as well as continue to look for other
opportunities that would allow for a cost effective method to collect daily customer usage data. Until that
time, Intermountain wil continue to collect daily Core market sendout which enables a daily Core market
usage calculation.
Therefore, the dependent variable, 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 diference between the customers at the beginning of the month and
the customers at the end of the month to the days of the month.
Independent Variables
The following independent variables were tested as explanatory variables that would help explain
changes in usage per customer:
1. Actual sixty-five heating degree-days (65HDD) for each day during the peak months
2. Intermountain Gas natural gas prices
3. Consumer Price Index
4. Bank Prime Loan Rate
5. 30-Year Conventional Mortgage Rate
6. Gross Domestic Product
7. Idaho Per Capita Personal Income
8. A weekend binary variable to establish whether or not a relationship exists between usage levels
and the weekend.
Methodology and Results
A regression equation was developed for each of the peak months. For the November, December, and
January models, the independent variables included in the model to explain changes in daily usage per
customer are, daily actual 65HDD, IGC prices and the weekend binary (see "Regression Equations,"
Exhibit 2, Appendix B). Neither IGC price, nor the weekend binary variable were significant in the
February model, so the 65HDD variable is the only explanatory variable in the February modeL.
Each of the selected models meets accepted standards for statistical soundness. The models all have
high R2 statistics which determine what percent of the variabilty in usage per customer is explained by
the independent variables. T-statistics for each of the variables indicate they are individually significant
(p~O.05). The models have all been corrected where necessary to ensure the Durbin-Watson statistic
falls within an accepted range, and the F-statistics indicate that the regression models are significant (See
"Regression Statistical Output," Exhibit 2, Appendix A).
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.
34
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Customer Usage During Non-Peak Months
Modeling usage per customer for the non-peak months begins with a slightly different data set than the
peak usage month models. The dramatically diferent usage patterns of the various classes of customers
during the non-peak months as well as a weaker link between weather and usage led Intermountain to
develop unique models for residential space heating customers (RS-1), residential space and water
heating customers (RS-2) and small commercial customers (GS). As discussed in the previous section,
Intermountain does not currently have the capabilty to collect daily usage by customer class. Therefore,
the Non-Peak month models begin as monthly usage models.
Variable Selection
Time Series
Intermountain has developed a database of historical monthly data going back to 1981. All three
customer class models were developed based upon data for this entire data series. However, as outlined
in the discussion of "Customer Usage During Peak Months" above, Intermountain has seen structural
shifts in the data based upon customer usage patterns and price realities. Since it is difficult to construct
variables that effectively model these structural shifts in the data, Intermountain also tested models based
upon the shorter datasets of 1991 forward and 2001 forward.
Intermountain found that the time series 2001 forward provided the best statistical fit for the RS-1 and RS-
2 customer classes. The Residential classes have seen rapid growth which would create a bigger impact
on them of the conservation and efficiency factors outlined above. In addition, they can be fairly
responsive to price signals.
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However, the longer time series of 1981 forward more accurately explained Small Commercial customer
usage. Although this customer class has grown, it has been at a slower rate than the residential classes.
In addition, the small commercial businesses represented in this class would be affected not only by price
signals, but also by business cycles. The longer data series may more accurately capture those business
cycle impacts.
Dependent Variable - Monthlv Usage Per Customer
To calculate separate models for each of the Core market customer classes (RS-1, RS-2 and GS),
Intermountain used monthly usage per customer data. The total usage data for the month was divided by
customers for that same month to arrive at usage per customer for a given month.
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Independent Variables
The following independent variables were tested for their statistical validity in explaining changes in usage
per customer:
1. Actual sixty-five heating degree-days (65HDD) weighted by customers
2. Intermountain Gas natural gas prices
3. Summer/winter seasonal natural gas prices
4. 2 and 3-year moving average natural gas price
5. Lagged Prices
6. Consumer Price Index
7. Bank Prime Loan Rate
8. 30- Year Conventional Mortgage Rate
9. Gross Domestic Product
10. Idaho Per Capita Personal Income
11. Idaho Housing Starts
Methodology and Results
A regression equation was developed for each of the three Core market customer classes. The model
for each customer class is slightly different, reflecting the unique characteristics of the class. The only
statistically significant independent variable that remained in the RS-1 model was actual 65HDD. The
35
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
RS-2 model uses the 65HDD variable as well as a two-year moving average price variable. The GS
model includes the 65HDD variable and a winter usage trend binary variable. (See "Regression
Equations," Exhibit 2, Appendix B).
Each of the selected models meets accepted standards for statistical soundness. The models all have
high R2 statistics which determine the percent of the variabilty in usage per customer explained by the
independent variables. T-statistics for each of the variables indicate they are individually significant
(p::0.05). The models have all been corrected where necessary to ensure the Durbin-Watson statistic
falls within an accepted range, and the F-statistics indicate that the regression models are significant (See
"Regression Statistical Output," Exhibit 2, Appendix A).
Since the models calculated monthly usage, the constant, price and trend variables were divided evenly
by the days of the month to arrive at a daily factor. Then, the heating degree day coefficient was
multiplied by design heating degree days for each day of the month. These components were added
together to arrive at daily usage for each day of the month.
Price Elasticity
With the volatile natural gas market we have seen in recent years, much interest has been generated in
quantifying price elasticity of demand for natural gas. The price elasticity of demand is defined as the
percent change in demand for each 1 % change in price.
Intermountain tested for the effect of price elasticity in both the non-peak and peak models during this IRP
process. In the non-peak models, price remained a significant variable in only the RS-2 equation. RS-2
customers use natural gas for both space and water heating, and may have a greater opportunity to
conserve natural gas than either RS-1 or GS customers. The RS-2 price elasticity was a 0.7% decline in
usage given a 10% price increase.
Price did not remain in the GS models as a significant explanatory variable. However, in reviewing the
statistics of the model, it appeared that perhaps something was influencing usage that was not being
captured by the weather variable alone. The GS customer class is very diverse, ranging from office
buildings all the way up to small food processors. The statistical "noise" created by this diversity may
have made it difficult to isolate the true response to price. Instead, a trend variable was tested that
showed a declining usage trend during the months of Oct - Mar. The inclusion of the trend variable was
beneficial to the statistics of the overall GS modeL. The trend variable captures efficiency factors as well
as a price response.
Intermountain also tested for price elasticity in the Peak Month models. A price coefficient was
statistically significant in the November, December and January models, allowing for the measurement of
a price elasticity response in those months. As previously noted, the price variable was not statistically
significant in the February modeL. The Peak Month Price Elasticity indicates that given a 10% price
increase during the peak months of November - January, Core market usage would decrease by roughly
0.5%.
Total Daily Usage
The total usage for each day was calculated by multiplying the usage per customer in both the peak and
non-peak periods by the appropriate customers for that day (see Demand Forecast Overview, page 13).
Total daily usage varied depending upon the customer growth assumption that was used (Le. low growth,
baseline, or high growth).
36
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Usage Per Customer By Geographic Area
In a service territory as geographically and economically diverse as Intermountain Gas Company's, we
recognize that there could be significant differences in the way that customers use natural gas based
upon their location on Intermountain's system. Particularly in areas that may require capital
improvements to keep pace with demand growth, Intermountain used several methods to analyze
whether there was a difference in usage patterns versus the Total Company usage per customer. The
areas of interest that Intermountain studied for possible usage per customer refinements included;
Canyon County, State Street lateral, Sun Valley lateral, and Idaho Falls lateraL.
CANYON COUNTY AND STATE STREET LATERAL
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The locations of both the Canyon County and State Street lateral areas of interest made it impossible to
segregate a daily usage per customer for either area. However, both areas are located in the most
populous region of the service territory. This means the Total Company data is already weighted more
heavily toward representing the Treasure Valley usage patterns. Thus, Intermountain determined the
Total Company equations accurately reflected the usage per customer patterns for both of these areas of
interest.
As the Heating Degree Days and Design Weather section outlines, Intermountain has developed Normal
and Design Degree Days for both Canyon County and the State Street lateral areas. The Total Company
usage per customer equations were applied to these area specific degree days to provide a unique usage
forecast that wil more accurately predict the loads for both Canyon County and the State Street LateraL.
SUN VALLEY LATERAL
Variable Selection
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Time Series
In the fall of 2002, Intermountain installed an additional meter on the Sun Valley Lateral to measure
natural gas throughput in addition to the existing pressure measurement. Because of an equipment
malfunctions, the data was lost for the 2003/2004 winter. In reviewing the data, it also became apparent
that the data for the 2005/2006 winter was quite low in comparison with other data we had for the area for
that time period. The decision was made to remove that year of data from the dataset. Thus, the final
dataset represents five years of data.
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Dependent Variable - Daily Usage per Customer
The dependent variable, daily usage per customer, was calculated by taking the total throughput from the
Sun Valley lateral meter and subtracting out the industrial load. The resulting Core market throughput
was then divided by residential and small commercial customers for each day. Daily customers were
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.
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Independent Variable
The following independent variables were tested as explanatory variables that would help explain
changes in usage per customer:
1. Actual sixty-five heating degree-days (65HDD)
2. Intermountain Gas natural gas prices
3. Consumer Price Index
4. Bank Prime Loan Rate
5. 30-Year Conventional Mortgage Rate
6. Gross Domestic Product
37
7. Idaho Per Capita Personal Income
8. A weekend binary variable to establish whether or not a relationship exists between usage levels
and the weekend.
9. Daily Snowfall totals
10. Daily Snowdepth totals
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Methodology and Results
A peak day regression equation was tested for the Sun Valley lateral that included data for the months of
November through February for the entire Sun Valley lateral time series outlined above. Daily actual
HDD65 and Daily Snowfall totals were both significant in explaining changes in usage per customer.
However, the resulting equation did a poor job of forecasting usage based on actual conditions. The
equation consistently under-forecast at higher actual degree day levels.
Intermountain then tested a model that only included data from the traditional peak month of January for
the time series outlined above. The statistics for this model were not strong, and it again performed
poorly when tested against actual data.
Intermountain is committed to providing safe, reliable service on a peak day. Because of this,
Intermountain was reluctant to use an approach that would err on the side of under-forecasting the
potential peak load for the Sun Valley lateraL.
Since the amount of data in the dataset did not allow for the development of robust regression equations,
Intermountain next looked at an average usage per customer per degree day. This method showed that
the usage on a peak day on the Sun Valley lateral was roughly 3 therms per customer higher than the
Total Company regression model forecast. To account for this difference, the peak day period on the Sun
Valley lateral was adjusted upward by three therms per customer.
IDAHO FALLS LATERAL
Variable Selection
Time Series
During the fall of 2004, Intermountain installed an additional meter on the Idaho Falls Lateral to measure
natural gas throughput in addition to the existing pressure measurement. Because of an equipment
malfunctions, the data was lost for the 2005/2006 winter. Thus, the final dataset represents four years of
data.
Dependent Variable - Daily Usage per Customer
The dependent variable, daily usage per customer, was calculated by taking the total throughput from the
Idaho Falls lateral meter and subtracting out the industrial load. The resulting Core market throughput
was then divided by residential and small commercial customers for each day. Daily customers were
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.
Independent Variable
The following independent variables were tested as explanatory variables that would help explain
changes in usage per customer:
1. Actual sixty-five heating degree-days (65HDD)
2. Intermountain Gas natural gas prices
3. Consumer Price Index
4. Bank Prime Loan Rate
5. 30- Year Conventional Mortgage Rate
6. Gross Domestic Product
38
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2011 - 2015 Integrated Resource Plan
7. Idaho Per Capita Personal Income
8. A weekend binary variable to establish whether or not a relationship exists between usage levels
and the weekend.
Methodology and Results
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A peak day regression equation was tested for the Idaho Falls lateral that included data for the months of
November through February for the entire Idaho Falls lateral time series outlined above. Daily actual
HDD65 were significant in explaining changes in usage per customer. The overall statistics for this model
were not strong, however, and the resulting equation did a poor job of forecasting usage based on actual
conditions.
Again, Intermountain's commitment to providing safe, reliable service on a peak day required the use of
an additional method for forecasting peak day load. Intermountain next looked at an average usage per
customer per degree day. This method showed that the usage on a peak day on the Idaho Falls lateral
was roughly the same as the forecast generated by the Total Company regression model applied to
unique Idaho, Falls lateral degree days. Therefore, Intermountain used this Total Company equation to
forecast peak day loads on the Idaho Falls lateraL.
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
INDUSTRIAL USAGE FORECAST
Introduction
A survey of the industrial customers served by Intermountain Gas Company ("Intermountain") was
completed in the spring of 2009 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 large volume contract customers, and identified their historical usage on an annual peak
month and peak day basis for the past two years ending 2008. 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 this survey were used to forecast three distinct and separate large volume customer
forecasts (High Demand, Base Case, and Low Demand) for a six year period, commencing in 2010. 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 utilzed to adjust the survey data base for two of the three
forecasts (Base Case and Low Demand). The 110 customers were further refined into six separate sub-
groupings comprised of:
. 16 potato processors
· 37 other food processors including sugar, milk, beef, and seed companies
. 3 chemical and fertilzer companies
· 18 light manufacturing companies including electronics, paper, and asphalt companies
. 27 schools and hospitals
. 9 other companies
Plant efficiency and getting the most production out of their plants using the least amount of energy is a
very high priority of the owners, operators, and managers of these large volume plants. In order to help
them with their natural gas needs and evaluation, Intermountain has developed and deployed an
industrial customer website with specific and timely usage reads. The information on this site is gathered
through the company's SCADA system, and is transferred to the web-based site, which can be accessed
by the appropriate plant personnel from their own location over the internet. This "real-time" information
has helped many of the plants with their energy conservation and efficiency needs.
Additionally, Intermountain has offered to consult and help direct leak detection and corrosion control
efforts on the natural gas piping systems within the customers' facilties.
All current customers 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.
Base Case Forecast
The Base Case forecast, or most expected forecast, was compiled using the surveys with adjustments
made to, reflect known changes of existing customers. The projected usage for the Base Case increased
11,237,178 therms, amounting to 4.72% growth over the five year period from the base year 2010.
Highlights for each of the market sectors under the Base Case forecast are as follows:
· The Potato Processors group is projected to experience modest growth over the five year period.
Demand for potato products is good and the supply looks to be very good. No new plants are on
the drawing boards in the near future. Most of the plants in this group are looking for ways to
conserve resources while stil getting the most out of production thus lowering the overall cost of
product unit.
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2011 - 2015 Integrated Resource Plan
· The Other Food Processors group is projected to increase by 5.3% with production increases in
several plants mostly in the milk and cheese industry.
. The three plants in the Chemicals/Fertilzers group wil continue at current levels with no
projected growth and production increases in the forecast. In their forecasts, the managers of
these plants assume imported fertilzers wil not, at least in the foreseeable future, affect their
operations.
. The Manufacturing group is projected to have growth across the entire group with paving and oil
products leading. There are also some planned plant expansions to increase manufacturing.
. The Institutional group is projected to grow at 1 % a year, due mainly to growth of the existing
facilties. Medical facilities as well as private and state schools are planning expansions.
· The increase in the other group is projected to increase 1.8% over the period due primarily to
some moderate expansions at some of the facilties in this group.
The following table summarizes the anticipated Industrial load forecast for the 2011 to 2015 planning
period.
Base Case Forecast by Market Segment
(Thousands of Therms)
Compound
Rate of
FY 11 FY12 FY13 FY 14 FY 15 Growth
Potato Processors 91,983 92,038 92,148 92,218 92,228 2.1%
Other Food
Processors 64,850 68,031 68,340 68,320 68,300 5.3%
Chemical &
Fertilzer 30,440 30,440 30,440 30,440 30,440 0.0%
Manufacturers 18,117 18,267 18,417 18,567 18,717 3.3%
Institutions 14,584 14.840 15,064 15,097 15.177 4.1%
Other 24,064 24,374 24,456 24,484 24,494 1.79%
Total Base Case
Forecast Therm
Sales 244,036 247,990 248,865 249,126 249,356 2.18%
High Demand Forecast
The High Demand, or most optimistic, usage forecast incorporate usage data directly from the survey with
adjustments. The HIGH case forecast starts out approximately 13.2% above the BASE case numbers.
The increase from the 2010 annual usage estimate of 269,585,000 therms is projected to increase
23,745,000 therms, or approximately 8.81% over the five year period. Highlights for each of the market
sectors under the High Demand forecast are as follows:
· Potato production is up from the 2008 IRP projections, and the future looks very good for the
potato industry. This scenario shows the processors flat, although at record high levels. The
record potato crop in 2009 is a two edge sword-great quality and yield but also higher prices.
Natural gas prices should stay steady and low which would keep the plants using gas rather than
oiL.
· Other Food Processors are projected to be flat across the reporting period again at record high
levels. Milk and cheese processors would have expanded and the milk producers would process
the entire surplus product. Those plants dealing with cattle are optimistic for steady increases in
output.
4r
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
· The ChemicaVFertilzer group is not projected to increase in size; however, all three plants in this
group project steady production and usage at high levels.
· The Manufacturing group is projected to have a slow steady increase with the addition of two new
manufacturing plants in the high tech industries.
· The Institutional group, which is made up mostly of schools and hospitals, is projected by the
survey to remain relatively stable with the addition of one new institution.
. The Other group is projected to expand by three relatively high usage plants and usage would be
flat across the reporting period in this high demand case.
The following table summarizes the anticipated changes to industrial demand over the planning horizon:
High Demand Forecast by Market Segment
(Thousand of Therms)
Compound
Rate of
FY 11 FY 12 FY 13 FY14 FY 15 Growth
Potato Processors 103,045 103,048 103,050 103,050 103,050 0.05%
Other Food
Processors 68,218 68,218 68,218 68,218 68,218 0.0%
Chemical &
Fertilzer 32,100 32,100 32,100 32,100 32,100 0.0%
Manufacturers 30,210 30,360 30,510 30,660 30,810 1.99%
Institutions 16,045 16,045 16,045 16,045 16,045 0.0%
Other 34,607 36,607 43,107 43,107 43,107 24.56%
Total High Demand
Forecast Therm
Sales 284,225 286,378 293,030 293,180 293,330 3.2%
Low Demand Scenario
The projected usage for this scenario is based upon the assumption that the agricultural economy wil be
weak and experience a drop in sales and production. It is also assumed that natural gas prices wil
increase but remain reasonably competitive. With those assumptions, downturns are projected in the
Potato Processing group with possible closure of a plant and production downturns at others. The Low
Growth Scenario projections start below the base case (18%) in 2010 with overall usage decreasing a
projected 16% over the period. A summary of the Low Growth scenario by market segment is as follows:
· The price of natural gas was assumed to be competitive against the delivered price of oiL. The
loss of a major processor has resulted in the lowest gas usage for the potato processing group.
Potato consumption is assumed to remain at current levels. This group, as a whole, looks at any
way possible to conserve energy and make its plants more efficient.
· In the Other Food Processor group, it is expected to lose one production facilty but the rest are
expected to remain steady. Existing facilties wil remain flat.
· The projection for the Chemical/Fertilzer group remains flat with no increase or decrease in
usage or production.
42
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· The Manufacturing group is also projected to increase over the period by 3.8% although starting
(15%) below the base case, assuming that no additional"High Tech" production occurs and no
unforeseen state or federal highway projects begin.
. The growth projection for the Institutional group in the low growth forecast is attributed to the
known expansion of universities, schools, and hospitals.
. Facilties in the Other group are projected to increase mainly due to some increased usage at
Mountain Home Air Force Base and electrical power generation. This projection assumes,
however, no sales for ethanol production.
The following table summarizes the anticipated load forecast by market segment under the Low Demand
scenario:
Low Growth Forecast by Market Segment
(Thousand of Therms)
Compound
Rate of
FY 11 FY 12 FY 13 FY14 FY 15 Growth
Potato Processors 78,940 78,940 78,940 78,940 78,940 0.0%
Other Food
Processors 48,425 48,425 48,425 48,425 48,425 0,0%
Chemical & Fertilzer 26,500 26,500 26,500 26,500 26,500 0.0%
Manufacturers 15,690 15,840 15,990 16,140 16,290 3.8%
Institutions 12,940 14,210 14,424 14,447 14,517 12.0%
Other 11,875 11,875 14,736 14,774 14,774 31.0%
Total Low Growth
Forecast Therm
Sales 194,370 195,790 199,014 199,216 199,446 2.6%
Firm Contract Demand
The survey sent to the industrial customers additional requested information regarding each customer's
future peak requirements and their forecasted annual usage. Some of the largest customers predict that
while their peak day may not increase, their off-peak day requirements could, due in part to their use of
varying work schedules,
The individual customer's peak day requirements wil be used to analyze potential future upgrades to the
existing laterals serving each community. The existing as well as any new customer's Maximum Daily
Firm Quantity (MDFQ) for each of the Large Volume Firm Services (LV-1), wil not be increased over the
projected period because the incremental firm transportation capacity, as contracted with Willams
Northwest Pipeline Company, would create additional cost to all customers. Additionally, the tariff service
listed above is limited to an annual usage of less than 500,000 therms per year.
The total Industrial Contract Demand has increased 11.5% above the 2008 IRP filng most of which was
added along or close to the Willam Northwest Pipeline and therefore does not affect the four areas of
concern that have been identified and explored throughout this IRP.
43
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
The current peak day requirements for the large volume contract customers are as follows:
Segments
Total Firm Daily
Demand Requirements
ITherms)
Large Volume Firm Sales Services (LV-1)
Firm Transportation Services
Total
12,850
869,497
882,347
44
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
LOAD DURATION CURVES
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The culmination of the demand forecasting process is aggregating the information discussed in the
previous sections into a forecast of future load requirements. A brief review of the methodology follows.
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The IRP customer forecast provides a total company daily projection through Planning Year (PY) 2015
and includes a forecast for each of the four capacity constrained segments of the distribution system
(Idaho Falls, Sun Valley, and State Street Laterals and Canyon County Area). Each forecast was
developed under three different customer growth scenarios - Base Case, High Growth and Low Growth,
as well as three different pricing scenarios - Base Price, Low Price, and High Price.
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The development of a design weather curve - which reflects the coldest historical weather patterns across
the service area - provides a means to distribute the Core market heat sensitive portion of the Company's
load on a daily basis. Applying Design Weather to the residential and small commercial usage per
customer forecast creates Core market usage-per-customer under design weather conditions. That
combined with the applicable customer forecasts yield a daily Core market load projection through PY15
for the totally system as well as each regional segment. A similar normal weather scenario was also
developed.
As discussed in the Industrial Forecast section, the forecast also incorporates the industrial CD from both
a company-wide perspective (interstate capacity) and the regional segments (distribution capacity). When
added to the Core market figures, the result is a grand total daily forecast for both gas supply and
capacity requirements including a break-out by regional segment.
Peak day sendout under each of these customer growth scenarios was measured against the currently
available capacity to project the magnitude, frequency and timing of potential delivery deficits, both from a
total company perspective and a regional perspective.
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Once the demand forecasts were finished and evaluation complete, the data was arranged in a fashion
more conducive to IRP modeling. Specifically, the daily demand data for each individual forecast was
sorted from high-to-Iow to create what is known as a Load Duration Curve (LDC). The LDC incorporates
all the factors that wil impact Intermountain's future loads. The LDC is the basic tool used to reflect
demand in the IRP Optimization ModeL.
It is important to note that the Load Duration Curves represent existing resources and are intended to
identify potential capacity constraints and to assist in the long term planning process.
Design PY 11 - PY 15 Customer Growth Summary Observations
Idaho Falls Lateral
The Low Growth customer forecast projects an increase in customers of 5,867 through PY15 (Oct 1,
2010 to Sep 30, 2015) which corresponds to an annualized average growth rate of 2.33%. Base Case
customers increase by 6,718 customers (2.67%) and High Growth customers increase by 9,287
customers (3.69%). When comparing the PY11 Base Case customer starting point (Oct. 1) of the 2009 ,
LDC to the current LDC, there is a decrease of 2,232 Base Case customers (4.4%). i
Sun Valley Lateral
The Low Growth customer forecast (PY11 - PY15) projects an increase of 562 customers (1%
annualized growth rate), Base Case customer forecast increases by 657 customers (1.17% annualized
growth rate), and High Growth customer forecast shows an increase of 911 customers (1.62% annualized
growth rate), When comparing the PY11 Base Case customer starting point (Oct. 1) of the 2009 LDC to
the current LDC, there is a decrease of 49 Base Case customers (.4%).
45
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Canyon County Area
The Low Case customer Forecast for Canyon County (CC) reflects an increase of 7,256 customers dunng
this IRP period (PY11 - PY15), which is an annualized growth rate of 3.25%. The Base Case customer
forecast for CC increases by 7,774 customers (3.49% annualized growth rate) over the 5-year period.
The High Growth customer forecast shows an increase of 8,324 customers (3.73% annualized growth
rate). When comparing the PY11 Base Case customer starting point (Oct. 1) of the 2009 LDC to the
current LDC, there is a decrease of 3,540 Base Case customers (7.9%).
State Street Lateral
The Low Case customer Forecast for the State Street Lateral (SSL) reflects an increase of 2,809
customers during this IRP period (PY11 - PY15), which is an annualized growth rate of 1.26%. The Base
Case customer forecast for CC increases by 3,007 customers (1.35% annualized growth rate) over the 5-
year period. The High Growth customer forecast shows an increase of 3,254 customers (1.46%
annualized growth rate). Because this is the first year that the SSL is in this IRP, there is no comparison
to the last IRP.
Total Company
The Low Growth customer forecast (PY2011 - PY15) projects an increase of 30,721 customers (2.03%
annualized growth rate), the Base Case customer forecast increases by 34,075 customers (2.26%
annualized growth rate), and the High Growth customer forecast shows an increase of 38,793 customers
(2.57% annualized growth rate). When comparing the PY11 Base Case customer starting point (Oct. 1) of
the 2009 LDC to the current LDC, there is a decrease of 12,064 Base Case customers (4,0%).
Using the LDC analyses, Intermountain wil be able to anticipate changes in future demand requirements
and plan for the use of existing resources and the timely acquisition of additional resources.
Price Elasticity Combined with Growth Scenario Comparisons
Having price elasticity in our load duration curves provides us with the opportunity to combine the
different pricing scenarios with the different growth scenarios to show us a 'highest usage case' and a
'lowest usage case'. For example, the highest customer usage would occur when combining the 'high'
customer growth case with the 'low' price scenano. The lowest customer usage would occur when
combining the 'low' customer growth case with the 'high' pricing scenario. The following tables show
these combined customer growth and pricing scenarios, as well as the 'base' growth and 'base' price
scenanos for comparison. These scenarios were run using both 'Design' and 'Normal' weather for the
Idaho Falls, State Street, and Sun Valley laterals, the Canyon County area, and the Total Company
scenario.
Idaho Falls
Idaho Falls Lateral Design Weather- Total Annual Usage (Dth)
Growth Scenario Price Scenario 2011 2012 2013 2014 2015
Low High 7,291,568 7,400,566 7,517,686 7,668,567 7,788,886
Base Base 7,329,551 7,482,163 7,620,103 7,804,194 7,952,499
Hiah Low 7,381,245 7,647,251 7,877,855 8,142,760 8,387,052
46
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Idaho Falls Lateral Normal Weather- Total Annual Usage (Oth)
Growth Scenario Price Scenario 2011 2012 2013 2014 2015
Low High 6,475,801 6,569,976 6,664,682 6,792,500 6,898,830
Base Base 6,504,050 6,637,718 6,759,675 6,918,319 7,049,907
High Low 6,554,623 6,791,154 6,997,125 7,231,711 7,449,728
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Sun Valley Lateral Design Weather- Total Annual Usage (Oth)
Growth Scenario Price Scenario 2011 2012 2013 2014 2015
Low High 1,772,767 1,782,444 1,788,456 1,804,265 1,818,726
Base Base 1,780,187 1,793,792 1,802,661 1,823,417 1,844,050
High Low 1,790,658 1,818,756 1,835,507 1,868,733 1,901,290
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Sun Valley Lateral Normal Weather- Total Annual Usage (Oth)
Growth Scenario Price Scenario 2011 2012 2013 2014 2015
Low High 1,533,592 1,539,725 1,543,948 1,556,761 1,568,964
Base Base 1,539,151 1,549,108 1,557,294 1,574,725 1,592,254
High Low 1,549,350 1,572,239 1,588,446 1,617,108 1,645,065
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Growth Scenario Price Scenario 2011 2012 2013 2014 2015
Low High 5,325,835 5,462,078 5,590,127 5,735,770 5,887,821
Base Base 5,360,341 5,522,941 5,651,247 5,821,338 5,987,972
High Low 5,404,220 5,620,233 5,778,039 5,973,739 6,158,030
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Canvon County Area Normal Weather- Total Annual Usage (Oth)
Growth Scenario Price Scenario 2011 2012 2013 2014 2015
Low High 4,597,890 4,710,428 4,810,193 4,931,972 5,061,423
Base Base 4,623,344 4,760,571 4,868,168 5,011,702 5,155,020
High Low 4,666,457 4,854,968 4,991,221 5,153,636 5,319,063
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
State Street
State Street Lateral Design Weather- Total Annual Usage (Dth)
Growth Scenario Price Scenario 2011 ' 2012 2013 2014 2015
Low High 5,455,565 5,483,546 5,509,922 5,563,936 5,625,140
Base Base 5,485,634 5,530,863 5,553,325 5,617,885 5,686,576
High Low 5,524,950 5,608,365 5,646,170 5,720,918 5,810,914
State Street Lateral Normal Weather- Total Annual Usage (Dth)
Growth Scenario Price Scenario 2011 2012 2013 2014 2015
Low High 4,846,918 4,868,954 4,883,004 4,927,739 4,980,916
Base Base 4,869,008 4,907,810 4,925,084 4,980,218 5,040,076
High Low 4,907,949 4,983,921 5,016,996 5,082,771 5,162,478
Total Company
Total Company Design Weather- Total Annual Usage (Dth)
Growth Scenario Price Scenario 2011 2012 2013 2014 2015
Low High 38,965,158 39,431,412 39,932,641 40,614,920 41,316,353
Base Base 39,184,793 39,822,755 40,352,066 41,193,564 42,006,805
Hiah Low 39,472,408 40,466,945 41,195,653 42,179,029 43,229,528
Total Company Normal Weather- Total Annual Usage (Dth)
Growth Scenario Price Scenario 2011 2012 2013 2014 2015
Low High 33,359,562 33,722,310 34,086,146 34,645,518 35,233,472
Base Base 33,520,863 34,044,481 34,479,501 35,181,981 35,870,320
High Low 33,804,509 34,665,613 35,290,399 36,127,257 37,027,131
Projected Capacity Deficits - All Scenarios
Residential, commercial and industrial peak day load growth on Intermountain's system is forecast over
the five-year period to grow at an average annual rate of 2.03% (low growth), 2.26% (base case) and
2.57% (high growth), highlighting the need for long-term planning. This section outlines capacity deficits
that would occur absent any corrective action by the Company.
Idaho Falls Lateral LDC Study
When forecast peak day sendout on the Idaho Falls lateral is matched against the existing peak day
distribution capacity (810,000 therms) in the base price scenario, a peak day delivery deficit occurs
beginning in PY11 for all scenarios and continues to increase at the levels shown on the following table:
48
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
IFL - Design Weather Peak Day Deficit Under Existing Resources (Dth)
ScenarioNear
Low Growth
Base Growth
High Growth
1,
2011 2012 2013 2014 2015
(9,275)
(9,309)
(9,382)
(11,777)
(12,335)
(14,466)
(16,432)
(17,849)
(23,043)
(21,457)
(24,080)
(32,261 )
(24,720)
(28,146)
(40,187)
Sun Valley Lateral LDC Study
When forecasted peak day send out on the Sun Valley Lateral is matched against the existing peak day
distribution capacity (17,500 therms), a peak day delivery deficit occurs starting in PY11 on all scenarios
and increases at the levels shown on the following table:
SVL - Design Weather Peak Day Deficit Under Existing Resources (Dth)
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Low Growth
Base Growth
High Growth
2011 2012 2013 2014 2015
(968)
(971)
(981)
(1,733)
(1,747)
(1,797)
(1,604)
(1,779)
(2,162)
(2,226)
(2,457)
(3,314)
(2,523)
(3,022)
(4,401)
Canyon County LDC Study
When forecasted peak day send out for the Canyon County region is matched against the existing peak
day distribution capacity (690,000 therms), a peak day delivery deficit does not occur, although in 2015
(High Growth) on the peak day, usage gets within 798 Dth of Design Capacity:
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CC Area - Design Weather Peak Day Deficit Under Existing Resources (Dth)
ScenarioNear
Low Growth
Base Growth
High Growth
2011 2012 2013 2014 2015
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o
o
o
o
o
o
o
o
o
°
°
o
State Street Lateral LDC Study
When forecasted peak day send out for the State Street Lateral is matched against the existing peak day
distribution capacity (585,000 therms), a peak day delivery deficit does not occur.
State Street Area - Design Weather Peak Day Deficit Under Existing Resources
(Dth)
ScenarioNear 2011 2012 2013 2014 2015
Low Growth °0 °°°
J Base Growth 0 °°°°
High Growth 0 0 °°0
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49
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
All Other LOC Study
No deficits are projected to occur in any of the locations making up the "All Othet' group on
Intermountain's system over the five-year study.
Total Company LOC Study
The Total Company perspective difers from the laterals in that it reflects the amount of gas that can be
delivered to Intermountain via the various resources on the interstate pipeline system. Hence, total
system deliveries should provide at least the net sum demand - or the total available distribution capacity
where applicable - of all the laterals/areas on the distribution system. The following table shows that there
are no annual peak day deficits based on existing resources:
Total Company - Design Weather Peak Day Surplus/(Deficit) Under Existing Resources (Dth)
ScenarioNear 2011 2012 2013 2014 2015
Low Growth
Base Growth
High Growth
99,800
99,673
99,627
94,218
93,711
92,866
87,577
86,353
84,539
79,338
77,293
74,346
69,280
66,217
61,896
50
- \
j Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
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TRADITIONAL SUPPLY-SIDE RESOURCES
Overview
The natural gas marketplace continues to change but Intermountain's commitment to act with integrity to
provide secure, reliable and price-competitive firm natural gas delivery to its customers has not. In today's
energy environment, Intermountain bears the responsibilty to structure and manage a gas supply and
delivery portolio that wil effectively, efficiently and with best value meet its customers' year-round energy
needs. Intermountain wil, through its long-term planning, continue to identify, evaluate and employ best-
practice strategies as it builds a portolio of resources that wil provide the value of service that its
customers expect.
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The Traditional Supply Resource section wil outline the energy and related infrastructure resources
"upstream" of the distribution system necessary to deliver energy to the Company's distribution system.
Specifically included in this definition is the natural gas commodity (or the gas molecule), various types of
storage facilties and interstate gas pipeline capacity. This section wil identify and discuss the supply,
storage and capacity resources available to Intermountain and how they may be employed in the
Company's portolio approach to gas delivery management.
Background
The procurement and distribution of natural gas is in concept a straightforward process. It simply follows
the movement of gas from its source through processing, gathering and pipeline systems to end-use
facilties where the gas is ultimately ignited and converted into thermal energy. Natural gas is a fossil fuel;
a naturally occurring mixture of combustible gases, principally methane, found in porous geologic
formations beneath the surface of the earth. Natural gas is produced or extracted by drillng into those
underground formations or reservoirs and then moving the gas through pipelines to customers in often far
away locations.
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Intermountain is fortunate to be located in between two of the most proliic gas producing regions in North
America. The first, the Western Canadian Sedimentary Basin (WCSB) in Alberta and northeastern British
Columba supplies nearly 55-60% of Intermountain's natural gas. The other region, known as the
"Rockies", includes many different producing basins in the states of Wyoming, Colorado and Utah where
the remainder of the Company's supplies are sourced. The Company also utilzes storage facilties to
essentially hold and save natural gas during periods of low customer demand for use during periods of
higher demand,
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Intermountain's access to the gas produced in these basins is wholly dependent upon the availabilty of
pipeline capacity to move that gas from those supply basins to Intermountain's distribution system. The
Company is also well positioned relating to pipeline capacity as this region has multiple interstate pipeline
options providing ample capacity to transport gas to Intermountain's Citygates. A basic discussion of gas
supply, storage and interstate capacity resources follow.
Gas Supply Resource Options
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The last decade has been one of confusing market signals for natural gas. The early part of the decade
saw growing demand for natural gas, maturing supply basins coupled with increasing challenges in
finding new reserves and production, supply bottlenecks due to natural disasters and strengthening
market prices. At the same time, interstate pipelines continued to expand transport capacity from
production areas with constrained access - particularly in the WCSB and the Rockies - to higher-priced
markets to the East which began to change regional price differentials. As well, the continued growth in
natural gas fired electric generation caused a fundamental change in the shape of the demand curve (see
Exhibit No.4, Chart 1).
One critical issue relating to natural gas is the drastic decline in reserves and production from regions that
have historically been top producers, Exhibit No.4, Chart 2 shows that production of offshore and
51
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
conventional gas supplies (the 3ra and 4th layers from the bottom of the chart) is in decline. The good
news is that improved technologies for finding and producing non-traditional gas supplies have led to
huge increases in gas supplies during this decade. Exhibit No.4, Chart 2 shows how coalbed, shale and
new Alaska production (the 5th through ¡lh layers) are not only replacing those declines, but are projected
to increase annual production levels through 2024.
Increased supplies coupled with softening demand due to the global economic downturn have led lower
natural gas prices and a pause in driling activities. These dynamic swings in supply and demand have
resulted in fundamental changes in the natural gas market. As a result, both consumers and producers
have seen extreme short and long term price volatilty along with changes in national and regional pricing
trends.
While natural gas prices continue to exhibit volatilty from a both national/global and regional
perspectives, the laws of supply and demand clearly govern the availability and pricing of natural gas.
For example, periods of higher demand tend to drive prices up which in turn generally results in
consumers seeking to lower consumption while producers typically increase investment in activities that
wil further enhance production. Thus, fallng demand coupled with increasing supplies tend to swing
prices lower. This in turn leads to fallng supplies, increased demand and the cycle begins anew. Finding
equilbrium in the market has been challenging for all market participants but at the end of the day, the
competitive market clearly works.
Supply Regions
As previously stated, Intermountain's natural gas supplies are obtained primarily from the WCSB and the
Rockies. Access to those abundant supplies is completely dependent upon the amount of transportation
capacity held on those pipelines so much that a discussion of the Company's purchases of natural gas
cannot be fully explored without also addressing pipeline capacity. On average, Intermountain purchases
approximately 55-60% of its gas supplies from the Western Canadian Sedimentary Basin in Alberta and
northeast British Columbia and the remainder from the Rockies. Exhibit No.4, Map 1 shows the largest
natural gas producing basins in North America.
Alberta
Production in this province has historically been abundant. In fact, at one time Alberta was believed to
have the largest natural gas reserves in the North American continent and annually produced 10 times
the Pacific Northwest's yearly consumption. However, this decade has seen production and reserve
declines and some forecasts indicate continuing declines in availabilty of export gas. The decline is result
of producers not being able to adequately replace the prolific shallow reserves and because more Alberta
gas is being used in the province to serve growing demand and in the production of tar sands oil. Finding
new reserves requires that producers dril deeper wells that generally produce lesser volumes. Lastly,
significant pipeline capacity exists to transport Alberta to the Eastern U.S. markets. Consequently, prices
for Alberta gas supply has remained strong as Northwest markets must compete for Alberta gas with
those traditionally higher priced markets in the Midwest and eastern U.S. Alberta supplies are delivered to
Intermountain via two Canadian pipelines (TransCanada Alberta or "Nova" and "Foothils") and two U.S.
pipelines (Gas Transmission Northwest "GTN" and Northwest Pipeline "Northwest") as seen on Exhibit
No.4, Map 2.
On the positive side, Alberta has begun to tap its vast regions of unrecovered coal seam and shale gas
reserves and has new found new reserves in the northwestern part of the province. Some of the more
recent reserve forecasts predict that provincial supplies wil actually show some slow growth as these new
plays are developed. Alberta is also well positioned to receive new supplies the next supply frontier in the
Northwest Territories as well as gas from the Alaskan North Slope and/or Canada's Mackenzie Delta
Arctic regions when exploration and production commence in those basins although these supplies wil
not be available for at least ten years, So, while the short-run supply availabilty from Alberta may tighten
somewhat, many longer-term forecasts project adequate export production although future exports wil
have to compete with growing U.S, supplies.
Intermountain continues to utilize a significant amount of Alberta supplies in its portfolio. The Stanfield
interconnect between NWP and GTN offers operational reliability and flexibility over other receipts points
52
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
both north and south. Where these supplies once amounted to a trickle in the Company's portolio,
today's purchases amount to approximately 40 percent of the company's annual purchases.
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British Columbia
BC has traditionally been a source of competitively priced and abundant gas supplies for the Pacific
Northwest. Gas supplies produced in the province are transported by Spectra Energy to an interconnect
with Northwest Pipeline near Sumas, WA. Historically, much of the provincial supply had been somewhat
captive to the region due to the lack of alternative pipeline options into Eastern Canada or the Midwest
U.S. However, pipeline expansions into Eastern Canada and the Midwest U.S. eliminated that bottleneck.
Coupled with declining production in some of the more traditional BC plays, supplies for export into the
Northwest have tightened. So, 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 for future
deliverabilty to Pacific Northwest 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 impede ultimate delivery to Intermountain's Citygates.
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Rockies
Rockies supply has historically been the second largest source of supply for Intermountain because of the
ever-growing reserves and production from the region coupled with firm pipeline capacity available to
Intermountain. Additionally, Rockies supplies have been readily available, comparatively inexpensive and
highly reliable. Historically, pipeline capacity to move Rockies supplies out of the region has been limited
which forced producers to compete with each to sell their supplies to markets with firm pipeline takeaway
capacity. Consequently, Rockies supplies tended to trade at lower prices than the Canadian or other U.S.
sources. However, several pipeline expansions out of the Rockies (e.g, Kern River and more recently the
completion of Rockies Express pipeline among others) have greatly minimized or eliminated most of the
capacity bottlenecks so these supplies now can now more easily move to higher priced markets found in
to the East or in California. Consequently, even though growth in Rockies reserves and production
continues at a rapid pace reflecting increased success in finding tight sand, coal seam and shale gas, the
more efficient pipeline system has essentially eliminated the price advantage that Pacific Northwest
markets have enjoyed. This is not to say that Rockies supplies wil be less available to Intermountain but
that this region must now compete, more than ever, with markets paying higher prices which wil likely
cause an increase in the cost of future purchased supplies.
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One remaining capacity constraint is found on the NWP system near Kemmerer, Wyoming Oust east of
the Idaho border) where the amount of Rockies supply flowing northwest into Idaho is limited. Through
capacity release opportunities on Northwest, Intermountain has obtained all the capacity it could with
receipt points from the Rockies. This allowed the Company to maximize the amount of Rockies supplies
that could be purchased which has helped to hold down the company's purchased cost of gas. Today
however, there is no excess Rockies capacity available and the cost of physically building new capacity
through the Kemmerer constraint point makes that alternative unlikely to happen. The Company therefore
must rely on available gas supply at Sumas and Stanfield as incremental supplies are needed in the
future.
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Imported LNG
Another potential supply for the U.S. is Liquefied Natural Gas (LNG) produced in such places as
Australia, Trinidad and Tobago and Qatar, which would then be shipped to ports in the U.S. LNG
shipments are generally off-loaded into permanent tanks where the liquid is stored until it is vaporized and
injected into a pipeline system. There are currently several operating LNG ports on the East and Gulf
coasts and one on the West coast in Northern Mexico. As a percent of total U.S. demand LNG deliveries
are comparatively small but growing. The global abundance of natural gas, declining gas production in
some North American basins and strong domestic demand makes imported LNG a viable alternative as a
future supply source. But since LNG is traded on the global market, where prices are typically tied to oil,
LNG is not yet competitive with North American natural gas prices on a large scale. However, if used to
enhance peaking deliveries or supplement baseload supplies, LNG may be a practical alternative.
In recent years, three separate import facilties have been proposed for the Pacific Northwest (all in
Oregon). As of the summer of 2010, two of those projects - Oregon LNG and Bradwood Landing - have
1,I
53
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
stalled for various reasons. Most industry analysts predict that at best, the Northwest market could only
support building one such facilty and today, the project with best chance appears to be Jordan Cove LNG
to be located near Coos Bay, Oregon. In conjunction with a new pipeline proposal, Jordan Cove would be
able to deliver over a billon cubic feet per day (Bet) of natural gas to markets in Western Oregon and
Northern California. Because the time frame to certificate and build these facilties takes years and due to
some local and/or state resistance to the project, this IRP assumes that no significant volume of imported
LNG wil be delivered into the Pacific Northwest by 2015. A map showing the location of the proposed
LNG projects is included as Exhibit No.4, Map 3.
Alaska and McKenzie Delta
It is known that huge reserves of natural gas exist off the Alaskan North Slope and Canada's McKenzie
Delta. However, there is currently no pipeline capacity to deliver these volumes to the North American
market although facilties with the capabilty to receive any such delivery do currently exist. Cost estimates
to build such capacity begins in the 30 bilions of dollars and adding such huge delivery cost to those gas
supplies would not be economic in today's market. Additionally, the time frame to plan, certificate and
build such facilties would take, by most estimates, up to a decade. In fact, many long term forecasts
predict that these supplies wil not be delivered into the North American market any sooner than 2020 and
therefore this IRP does not include any these supply in its assumptions. Finally, with the rate of growth in
U.S. production, delivery of these supplies to markets in the U.S. may be much further out on the horizon.
Types
There are essentially two main types of supply: firm and interruptible. Firm gas commits the seller to make
the contracted amount of gas available each and every day during the term of the contract and commits
the buyer to take that gas on each and every day. The only exception would be force majeure events
where one or both of the parties cannot control external events that make delivery or receipt impossible.
Interruptible or best efforts gas supply typically is bought and sold with the understanding that either party
for various reasons, do not have a firm or binding commitment to take or deliver the gas.
Intermountain builds its supply portolio on a base of firm, long-term gas supply contracts but includes all
of the types of gas supplies as described below:
1. Long-term: gas that is contracted for a period of over one year.
2. Short-term: gas that is often contracted for one month at a time.
3. Spot: gas that is for some reason not under a long-term contract; it is generally
purchased on a short term basis with a term of anywhere from one day up to periods of
one month or even several months.
4. Winter Baseload: gas supply that is purchased for a multi-month period most often during
winter or peak load months.
5. Citygate Delivery: natural gas supply that is bundled with interstate capacity and
delivered to the utilty Citygate meaning that it does not use the Company's existing
capacity.
As the natural gas market continues to mature, liquidity at the purchases points Intermountain utilzes has
allowed for more flexibilty in the structure of the portolio. The historical heavy reliance on mostly longer-
term contracts for the majority of the portolio lessened as the Company found that it can shift more of its
supplies to shorter termed contracts. Doing provides a better abilty to balance supplies with seasonal
demand and take advantage of price shifts without having excess supply in off-peak periods.
Pricing
Long-term firm supplies have historically been priced flat to, or at a small premium to, the applicable
monthly index priced. As market conditions change over time, Intermountain has found that contracts
containing negotiable market sensitive price premiums or discounts allow both buyer and seller to be
more comfortable that longer term contracts remain market competitive. The Company also actively
manages its various firm receipt points so that to the extent possible, purchases are made at the lowest
price possible. Intermountain includes several year-round and winter-only term supply contracts in its
portolio.
54
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
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, day-to-day 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 often, but not always, inexpensive when compared to term
supply.ldl
Intermountain frequently purchases firm spot supplies for a given month and as a rule, targets those
suppliers with reputation for reliabilty. Intermountain is also active in the spot market as it manages its
daily position with the various pipelines on which it flows gas supplies. The Company may use
interruptible supplies when a failure to delivery would not result in a risk of serving its firm customers. For
example, interruptible may be used to supplement summer storage injections because a failure would not
jeopardize any customers and the injection could be easily be made up on a subsequent day. Of course,
in order to purchase such gas supply, the Company would require an attractive price.
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To help manage price risk, the Company also utilzes NYMEX based products to "hedge" forward prices.
Intermountain most often uses price swaps or fixed for floating agreements. The instruments provide
Intermountain with the opportunity to lock-in future prices and avoid the sometimes wild market volatilty
(Exhibit No.4, Chart 3 shows historical monthly index prices at the main pricing points Intermountainutilzes.) While the Company does not utilze a fully mechanistic approach, its Gas Supply Committee
meets frequently to discuss all gas portolio issues, including price hedging, in order to provide stable and
competitive prices for its customers.
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For optimization purposes, Intermountain obtained two five-year price forecasts for the Aeco, Rockies and
Sumas pricing points from two multi-national energy companies based on the January 6, 2010 market
close. After evaluation, it was determined that although the forecasts were not perfectly identical (as
would be expectéd), the trends and seasonal pricing levels were actually very similar to one another.
Therefore, the Company determined that it could reasonably use one the forecasts for modeling
purposes. The selected forecast not only included a monthly base price projection for each of the three
purchase points but also included forecasts for plus and minus one standard deviations as well as plus
and minus two standard deviation projections.
Because the two standard deviation projections seemed too extreme, Intermountain chose to use the plus
one and minus standard deviation price forecasts to "band" the base price projection for modeling usage
under higher or lower price conditions. Exhibit No.4, Charts 4 through 6 shows the relationship between
those various forecasts. For each scenario, the wholesale price forecasts were also used to project retail
prices so that the therms per customer projections could be adjusted to account for prices where
applicable.
Storage Resources
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As previously discussed, the production of natural gas and the amount of available pipeline capacity are
very linear in nature; changes in temperatures or market demand does not materially affect how much of
either is available on a daily basis. As seen in the Load Duration Curve section of this IRP, the steep drop
off in core market demand means that attempting to serve peak demands with a level amount of gas
supplies and pipeline capacity would be enormously expensive as the vast majority of those resources
would be utilzed, at best, only a few days each year. So the abilty to store natural gas during periods of
non-peak demand for use during peak periods is a cost efficient way to fil the gap between static levels of
supply and capacity vs. the non-linear demand curve,
Intermountain utilzes storage capacity in four different facilties from western Washington to northeastern
Utah. Two are operated by Northwest: one is an underground project located near Jackson Prairie, WA
("JP") and the other is liquefied gas (LS) facilty located near Plymouth, W A. Intermountain also leases
capacity from Questar Pipeline's Clay Basin underground storage field and also operates its own LS
facility located in Nampa, ID (See Exhibit No.4, Map 3 for facilty locations).
55
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
All four locations allow Intermountain to inject excess gas into storage during off-peak periods and then
hold it for withdrawal whenever the need arises. The advantage is three-fold: one, the Company can
serve the winter peak and while minimizing year-round firm gas supplies; two, storage allows the
Company to minimize the amount of the year-round interstate capacity resource and helps it to use
existing capacity more efficiently; and three, storage provides a natural price hedge against the typically
higher winter gas prices. Thus storage allows the Company to meet its winter loads more efficiently and at
a generally lower a cost.
Liquefied S,torage
Liquefied storage facilties make use of a process that supercools and liquefies gaseous methane under
pressure until it reaches approximately minus 260°F. 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. LNG is also safe and non-toxic; it is non-corrosive and wil only burn when vaporized to a
5-15% concentration with air. Because of the characteristics of liquid, its natural propensity to vaporize
and the enormous amount of energy stored, LNG is normally stored in man-made steel tanks.
Liquefying natural gas is, relatively-speaking, a time-consuming process and the compression and
storage equipment is costly. It typically requires as much as one unit of natural gas burned as fuel for
every three to four units liquefied. Also, a full liquefaction cycle may take 5 - 6 months to complete.
Because of the high cost and length of time involved filing a typical LNG facilty, it is normally "cycled"
only once per year and is reserved for peaking purposes. This makes the unit cost somewhat expensive
when compared to other options.
Vaporization, or the process of changing the liquid back into the gaseous state, on the other hand, is a
very efficient process. Under typical atmospheric and temperature conditions, the natural state of
methane is gaseous and lighter than air as opposed to the dense state in its liquid form. Consequently,
vaporization requires little energy and can happen very quickly. Vaporization of LNG is usually
accomplished by utilzing pressure differentials by opening and closing of valves in concert with some hot-
water bath units. The high pressure LNG is vaporized as it is warmed and is then allowed to push itself
into the lower pressure distribution system. Potential LNG daily withdrawal rates are normally large and,
as opposed to the long liquefaction cycle, a typical full withdrawal cycle may last less than 10 days or less
at full rate. Because of the cost and cycle characteristics, LNG withdrawals are typically reserved for
"needle" peaking during very cold weather events or for system integrity events.
Neither of the two LNG facilities utilzed by Intermountain requires the use of year-round transportation
capacity for delivery withdrawals to Intermountain's customers. The Plymouth facilty is bundled with
redelivery capacity for delivery to Intermountain and the Nampa LNG tank withdrawals go directly into the
Company's distribution system. The IRP assumes liquid storage wil serve as a needle peak supply,
Underground Storage
This type of facilty is typically found in naturally occurring underground reservoirs or aquifers (e.g.
depleted gas formations, salt domes, etc.) or sometimes in man-made caverns or mine shafts. These
facilties typically require less hardware compared to LNG projects and are usually less expensive to build
and operate than liquefaction storage facilities. In addition, commodity costs of injections and withdrawals
are usually minimal by comparison, The lower costs allow for the more frequent cycling of inventory and
in fact, many such projects are utilzed to arbitrage variations in market prices.
Another material difference is the maximum level of injection and withdrawaL. Because underground
storage involves far less compression as compared to LNG, maximum daily injection levels are much
higher and so a typical underground injection season is much shorter, maybe only 3-4 months. But the
lower pressures also mean that maximum withdrawals are typically much less than liquefied storage at
maximum withdrawaL. So it could take 35 days or more to completely empty an underground facility. The
longer withdrawal period and minimal commodity costs make underground storage an ideal tool for winter
baseload (i.e, fillng the winter "hump" in the LDC) or daily load balancing and therefore Intermountain
normally uses underground storage before liquid storage is withdrawn.
56
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
The facilty with the largest amount of seasonal storage and daily withdrawal is Questar Pipeline's
("Questar") Clay Basin facilty in Northeastern Utah. However, since Clay Basin is not bundled with
redelivery capacity, Intermountain must use its year-round capacity when these volumes are withdrawn.
For this reason, the Company normally "base loads" Clay Basin withdrawals during the November-March
winter period. Just like Northwest's Plymouth LS facilty, Northwest's JP is bundled with redelivery
capacity and so Intermountain typically layers JP withdrawals between Clay Basin and its LS withdrawals.
The IRP uses Clay Basin as a winter baseload supply and JP is used as the first "layer" of peak supply.
The Table below outlines the Company's storage resources for this IRP.
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Table 1
Storage Statistics
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Facilty
Nampa
Plymouth
Subtotal Liquid
Seasonal
Capacity
580,000
1,096,235
1,676,235
Jackson Prairie
Clay Basin
Subtotal Undgrnd
1,099,099
8,413,500
9,512,599
Grand Total
Daily Withdrawal
Maximum % of Peak
60,000 17%
113,200 31%
173,200 48%
30,337 8%
70,109 19%
100,446 28%
273,646 lß
Daily Injection
Max Vol 1 # of Days
3,500 166
5,660 200
9,160
Redelivery
Capacity
None
TF.2
30,337 36
53,933 156
84,270
TF-2
TF-1
1 These figures are based on tariff or contact language; however real-world experience suggests that Plymouth and Clay Basin
average daily injections are much higher therefore the number of injection days are less.
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All four storage facilties require the use of Intermountain's every-day, year-round capacity for injection or
liquefaction. Because injections usually occur during the summer months, use of year-round capacity for
injections actually helps the Company to make more efficient use of its every-day transport capacity and
term gas supplies during those off-peak months when the Core Market loads are so low,
Storage Summary
The company generally utilizes its diverse storage assets to offset winter load requirements, provide peak
load protection and, to a lesser extent, for system balancing. Intermountain believes that the geographic
and operational diversity of the four facilties utilized offers the company and its customers a level of
efficiency, economics and security not otherwise achievable. Geographic diversity provides security
should pipeline capacity become constrained in one particular area. The lower commodity costs and
flexibilty of underground storage allows the company flexibilty to determine its best use from other supply
alternatives such as winter baseload or peak protection gas, price arbitrage or system balancing.
Interstate Pipeline Transportation Capacity
As earlier discussed, Intermountain is dependent on pipeline capacity to move natural gas from the areas
where it is produced, to end-use customers who consume the gas. In general, firm transportation capacity
provides a mechanism whereby a pipeline wil reserve the right, on behalf of a designated and approved
shipper, to receive a specified amount of natural gas supplies delivered by that shipper, at designated
points on its pipeline system and subsequently redeliver that volume to particular delivery point(s) as
designated by the shipper,,j
Intermountain holds firm capacity on four different pipeline systems including Willams Northwest Pipeline
("Northwest" or "NWP"). Northwest the only interstate pipeline with interconnects to Intermountain's
57
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
distribution system meaning that Intermountain physically receives all gas supply to its distribution system
via "Citygate" taps with Northwest. Table 1 below summarizes the Company's year-round capacity on
Northwest (TF-1) and its storage specific redelivery capacity. Intermountain holds enough Upstream
capacity on the GTN, Foothils, and Nova systems to deliver a volume of gas commensurate with the
Company's Stanfield takeaway capacity on Northwest.
Table 2
Northwest Pipeline Transport Capacity
Delivery Quantity 2011 2012 2013 2014 2015
TF-1 Capacity-
Sumas 41,146 41,146 41,146 41,146 41,146
Stanfield 115,429 115,429 115,429 115,429 115,429
Rockies 92,552 91,801 91,050 90,249 87,384
Citygate 26,000 26,000 26,000 26,000 26,000
Total TF-1 275,127 274,376 273,625 272,824 269,959
Storage (TF-2)143,537 143,537 143,537 143,537 143,537
Max. Cit ate Deliver 418.664 417.913 1 416.361 4
Northwest's facilities essentially run from the Four Corners area north to western Wyoming, across
Southern Idaho to Western Washington. The pipeline then continues up the 1-5 corridor where it
interconnects with Spectra Energy, a Canadian pipeline in British Columbia, near Sumas, Washington
where it receives natural gas produced in northeast British Columbia. Gas supplies produced in the
province of Alberta Northwest are delivered to Northwest via Gas Transmission Northwest (GTN) near
Stanfield, Oregon. Northwest also connects with other U.S. pipelines and gathering systems in several
western U.S. states ("Rockies") where it receives gas produced in basins located Wyoming, Utah,
Colorado and New Mexico, The major pipelines with which NWP interconnects can be seen on Exhibit
No.4, Map 1.
Because natural gas must flow along pipelines with finite flow capabilties, frequently demand cannot be
met from a market's preferred basin. Competition among markets for these preferred gas supplies can
cause capacity bottlenecks and these bottlenecks often result in pricing variations between basins
supplying the same market area. In the short to medium term, producers in constrained basins invariably
must either discount or in some fashion differentiate their product in order to compete with other also
constrained supplies. In the longer run however, disproportionate regional pricing encourages capacity
enhancements on the interstate pipeline grid, from producing areas with excess supply, to markets with
constrained delivery capacity. Such added capacity nearly always results in a more integrated, efficient
delivery system that tends to eliminate or at least minimize such price variances.
Consequently, new pipeline capacity - or expansion of existing infrastructure - in western North America
has increased take-away capacity out of the WCSB and the Rockies, providing producers with access to
higher priced markets in the Midwest and in California. Therefore, less-expensive gas supplies once
captive to the Northwest region of the continent, now has greater access to the national market resulting
in less favorable price differentials for the Pacific Northwest market. Today, wholesale prices at the major
trading points supplying the Pacific Northwest region are trending towards equilibrium indicative of a
fungible commodity. At the same time, new shale gas production in the mid-continent is beginning to
displace traditionally higher-priced supplies from the Gulf coast which, from a national perspective,
appears to be causing an overall softening trend in natural gas prices.
So today Intermountain is in an increasingly mega-regional marketplace where market conditions across
the continent can, and often do, affect regional supply availabilty and pricing dynamics. While gas
supplies are readily available and national prices show a short-term softening trend, Intermountain is
increasingly competing with markets that have historically paid higher prices to obtain gas supplies and
58
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
are actively building capacity to access the traditionally lower-priced supplies in the Rockies. In the long
run, many forecasts predict tightening price differentials across the continent.'~1
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Capacity Release
Capacity release was implemented to allow markets to more efficiently utilze pipeline capacity. This
mechanism allows a shipper with any unused capacity, to auction the excess to another shipper offering
the highest bid. Thus capacity that would otherwise sit idle can be used by a replacement shipper. The
result is a more efficient use of capacity as replacement shippers maximize the throughput of existing
capacity. One result is that pipelines are less inclined to build new capacity until the market recognizes
that it is really needed and is willng to pay for new infrastructure. But a fuller pipeline can also mean
existing shippers find less operational flexibilty.
Intermountain has and continues to be active in the capacity release market. Intermountain has obtained
quite a bit of capacity on Northwest and GTN via capacity release. The Company frequently releases
seasonal and/or daily capacity during periods of reduced demand. In the past, Intermountain utilzed a
specific type of capacity release called segmentation to move firm receipt capacity from Sumas to
Stanfield. Doing so not only provided certain capacity release credits but also provided more supply
diversity as reliance on BC supplies was decreases.
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Capacity release also resulted in a bundled service called Citygate delivered gas supplies as some
marketers were able to use available capacity to sell gas directly to a market's gate stations. Thus a
market like Intermountain could contract for supplies only for a specified time period - a peak or winter
period for example - that would ensure delivery of additional gas supplies without having to contract more
year-round capacity could very not be used during off peak periods.
New Pipeline Capacity
There are currently several pipeline projects proposed for the Northwest (see Figure 1 below). Two are
designed to increase capacity into the 1-5 corridor between Seattle and Portland (Blue Bridge and
Palomar) and another wil increase capacity in southern BC (Southern Crossing). The other pipeline,
Ruby Pipeline, would connect Rockies supplies into the Opal, Wyoming area for delivery at its terminal
point near Malin, Oregon where GTN interconnects with the PG&E in northern California. Two
competitors to the Ruby pipeline could not garner enough interest and appear to be cancelled.
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None of the these pipeline proposals would directly deliver gas supply into Idaho but it is possible that
through displacement (i.e. as more gas moves into the Pacific Northwest, it offsets other gas supplies
traditionally flowing into the same are), gas supplies typically flowing to markets on the west coast could
be available to the existing markets in Idaho. Alternatively, it could be possible to backhaul supply from
the interconnect where Ruby crosses Paiute Pipeline in Nevada into Northwest Pipeline in southern Idaho
but no information is presently available.
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Regulation
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 the
Federal Energy Regulatory Commission (FERC). For in-
state regulatory matters, the Idaho Public Utilties
Commission ("I PUC") provides oversight and oversees all
aspects of natural gas service to Intermountain's
customers. Under tariffs approved by the IPUC,
Intermountain provides sales and transport-only services
to over 305,000 customers in southern Idaho.
The vast majority of Intermountain's customers - including
all residential and commercial customers - receive a fully-
bundled sales service where the Company provides the
natural gas and all transportation capacity needed to
deliver natural gas directly to the customer's meter. A
59
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
handful of the Large-volume (also called "Industrial") customers also receive the bundled sales service.
However, most of Intermountain's industrial customers receive transport-only service on the distribution
system under two different tariffs. Intermountain's T -4 and T -5 customers receive firm distribution-only
transport where the customer's gas is received at the Company's applicable Citygates and then
transported through the Company's distribution system and redelivered to the customers' facilities. The
Company also transports gas under a similar T -3 tariff except that redelivery to the customer's facilties is
provided on interruptible basis.
Supply Resources Summary
Because of the dynamic environment in which it operates, the Company wil continue to evaluate
customer demand in order to provide an efficient mix of the above supply resources so as meet its goal of
providing reliable, secure, and economic firm service to its customers. Intermountain actively manages its
supply and delivery portolio and consistently seeks additional resources where needed. The Company
actively monitors natural gas pricing and production trends in order to maintain a secure, reliable and
price competitive portolio and 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. The IRP process culminating in the optimization modeling helps to
ensure that the Company's strategies to meet its traditional gas supply goals are based on sound, real-
world principles.
60
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
NON-TRADITIONAL SUPPLY RESOURCES
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Non-traditional supply resources help supplement the traditional supply-side resources during peak
demand conditions. Non-traditional resources include two general types: energy supplies not received
from an interstate pipeline supplier, producer or interstate storage operator and various methods used to
increase capacity within the Company's distribution system that enhance the abilty to flow gas during
periods of peak demand. Six (6) non-traditional supply resources and three (3) capacity upgrade options
were considered in this IRP and are as follows:
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Non-Traditional Supply Resources
1. Fuel Oil
2. Coal
3. Wood Chips
4. Propane
5. Remote/Portable LNG Facilities
6. Biofuel Production
Capacity Upgrades
1. Pipeline Loop
2. Pipeline Uprate
3. Compressor Station
Non-Traditional Supplies
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While a large volume industrial customers' load profie is relatively flat compared to the Core Market, the
industrials are stil a significant contributor to overall peak demand. However, some industrials have the
ability to use alternate fuel sources to temporarily reduce their reliance on natural gas. By using
alternative energy resources such as fuel oil, coal, propane and wood chips, an industrial customer can
lower their natural gas requirement during peak load periods while continuing to receive the energy
needed for their specific process. Although these alternative resources have the ability to be used at any
time, they are ideally suited to be applied during peak demand. However, only the industrial market has
the abilty to use any of the aforementioned alternate supplies in large enough volumes to make any
material difference in system demand. More specifically, only industrial customers located along the
Idaho Falls Lateral have the abilty to use any of these non-traditional resources. In order to rely on these
types of peak supplies, Intermountain would need to engage in negotiations with specific customers to
ensure availabilty. The overall expense cost of these kinds of arrangements, if any, is difficult to assess.
The two remaining non-traditional resources, Remote/Portable liquid natural gas (LNG) facilties and bio-
fuel production, are technically not forms of demand side management but they do have the abilty to
provide additional natural gas supply at the most favorable locations within a potentially constrained
distribution system. They can therefore supplant the normal capacity fixes - capacity related upgrades to
the distribution system. The abilty to create new, portable supply points can maximize capacity
possibilities in existing distribution systems.
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Fuel Oil
There are two large volume industrial customers along the Idaho Falls Lateral (IFL) that currently have
the abilty to use fuel oil as a natural gas supplement. The plants are able to switch their boilers over to
burn oil and decrease a portion of their gas usage, up to 35%, but neither plant has the abilty to run in full
operation with oil alone. Burning fuel oil in lieu of natural gas requires various permitting from the local
governing agencies, increases the level of emissions from the plant, and can have a lengthy approval
process depending on the specific type of fuel oil used.
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61
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Capital costs for fuel oil facilties are approximately $150,000 - $250,000 providing 10,000 - 15,000
therms per day offset. One industrial customer currently does not maintain oil storage onsite, but has the
abilty to store approximately three days of oil supply; the second customer currently doesn't have
updated permits for oil burn. The estimated cost of oil is between $1 .80 - $2.10 per gallon depending on
contractual obligations and time of year. (Note: one gallon of fuel oil is typically 138,000 - 155,000 BTU,
depending on grade and blending which calculates into $1.16 - $1.52 per therm.) Fixed operation and
maintenance (O&M) costs are approximately $60,000 - $120,000 per year.
Coal
Coal use is very limited as a resource for industrial customers within Intermountain's service territory. A
coal user must have a separate coal burning boiler installed along with their natural gas burning boilers
and typically must have direct railroad access to transport the large quantities of coal required to fuel their
boilers. Regulations and permitting requirements can also be a challenge. Intermountain currently has
one institutional, industrial customer capable of and willng to burn coal on the IFL. This customer
typically supplements their winter gas usage with coal and has the abilty to run completely on coal if
requested. At maximum usage they would offset 1,800 therms of natural gas each day.
The cost of coal in the northwest ranges from $30.00 - $60.00 per ton, depending on the quality of the
coaL. Lower BTU coal would range from 8,000 - 13,000 BTU per pound while higher quality coal would
range from 12,000 - 15,000 BTU per pound. This translates into a per therm cost of coal roughly at $0.18
- $0.25 plus rail transportation, permitting and equipment O&M costs.
Wood Chips
Using wood chips as alternative fuel is a practice utilized by one large volume industrial customer on the
IFL. In order to accommodate wood burning additional equipment must be installed, such as wood fired
boilers and storage facilties for the wood chips. The wood is supplied from various tree clearing and
wood mil operations that produce chips within regulatory specifications to be used as fueL. The chips are
then transported by truck to location where the customer wil typically store a two (2) to three (3) month
supply. The wood fired boilers are currently used on a full-time basis in conjunction with natural gas
boilers, 'and technically won't offset gas usage, For comparison purposes, the wood fired boilers, if used
to replace natural gas for this specific industrial customer, could offset gas usage by approximately 5,000
therms per day. Unfortunately, this single customer does not have the ability to utilze any more wood
fuel than they are currently using.
The cost of wood is continually changing based on transportation, availabilty, location and the type of
wood processing plant that is providing the chips. Wood has a typical value of 4,500 BTU per pound,
which converts into twenty two (22) pounds of wood being burned to produce one (1) therm of natural
gas. An approximate cost of purchasing wood chips in the northwest is estimated at $70.00 - $100.00 per
ton or $.77 - $1.10 per thermo
Propane
Since propane is similar to natural gas the conversion to propane is much easier than a conversion to
most other alternative resources. With the equipment, orifices and burners being similar to that of natural
gas, an entire industrial customer load (boiler and direct fire) may be switched to propane. Therefore,
utilzing propane on peak demand could reduce an industrial customer's natural gas needs by 100%. The
use of propane requires onsite storage, additional gas piping and a reliable supply of propane to maintain
adequate storage. Currently there are no industrial customers on the system that have the abilty to use
propane as an alternative to natural gas.
Capital costs for propane facilties are considerably higher than that for fuel oiL. Typical capital costs for a
peak day send out of 30,000 therms per day, and the storage tanks required to sustain this load, are
approximately $600,000 - $700,000. As with oil, storage facilities should be designed to accommodate a
peak day delivery load for approximately seven (7) days thus requiring the facilties to be refiled with
propane weekly at a cost ranging from $1.00 - $1.50 per gallon. (NOTE: One gallon of propane is
approximately 92,000 BTU). Fixed O&M costs are approximately $50,000 - $100,000 per year,
62
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Remote/Portable LNG Equipment
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Remote/Portable LNG equipment allows natural gas to be transported in tanker trucks in a liquid form;
meaning that larger quantities can be delivered to key supply locations throughout the distribution system.
Liquefied natural gas has tremendous withdrawal capability due to the natural gas being in a different
state of matter. Portable equipment has the abilty to boil LNG back to a gaseous form and deliver it into
the distribution system by heating the liquid from -260°F to a typical temperature of 50° - 70°F. This
portable equipment is available to lease or purchase from various companies and can be used for peak
shaving at industrial plants or within a distribution system. Regulatory and environmental approvals are
minimal compared to permanent LNG plants and are dependent upon the specific location where the
portable LNG equipment is placed. The available delivery pressure from LNG equipment ranges from
150 psig to 650 psig with a flow capabilty of approximately 2,000 - 8,000 therms per hour.
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Intermountain Gas recently purchased a portable LNG unit which is currently in operation on the Idaho
Falls Lateral to peak shave the northern end of the system. In addition to the portable equipment,
Intermountain also has a permanent LNG facilty on the IFL that is designed to accommodate the portable
equipment, provide an onsite control building and allow onsite LNG storage capabilties. The abilty to
store LNG onsite allows Intermountain to partially mitigate the risk associated with relying on truck
deliveries during critical flow periods. This particular permanent facilty is designed to store up to two (2)
days of LNG onsite, and along with the portable equipment, has the ability to send out approximately
50,000 - 90,000 therms per day depending on demand.
The cost of the portable LNG equipment is approximately $1 - $2 milion with additional cost to either
lease or purchase property to place the equipment and the cost of the optional permanent LNG facilty.
The fixed cost to lease the portable equipment is approximately $200,000 - $300,000 per month plus the
cost of LNG. The price of LNG is dependent upon time of usage, natural gas prices, liquefaction charges,
and transportation costs.
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Biofuel Production
Biogas can be defined as utilizing any biomass material to produce a renewable fuel gas. Biomass is any
biodegradable organic material that can be derived from plants, animals, animal byproduct and municipal
solid waste. After processing of biogas to industry purity standards the gas can be used as a renewable
supplement to fossil natural gas within Company facilities.
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Idaho is one of the nation's largest dairy producing states which make it a prime location for biogas
production utilzing the abundant supply of animal byproduct. Southern Idaho has currently seen two
dairy farms with test facilities containing anaerobic digesters that capture methane and carbon dioxide
from animal waste that would normally have been released into the atmosphere. These test facilties
have proven the abilty to produce acceptably pure natural gas, but currently do not transfer any product
into Intermountain facilties. As this technology advances and the need for renewable resources increases
there is a foreseeable potential for increased biofuel production within Intermountain's service territory
and this alternative supply remains an attractive and viable option that Intermountain continues to
monitor.
Capacity Upgrades
The three capacity upgrades discussed below do not reduce demand nor do they create additional supply
points, rather they increase the overall capacity of a pipeline system while utilzing the existing gate
station supply points.
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Pipeline Loop
Pipeline looping is a traditional method of increasing capacity within an existing distribution system. The
loop refers to the construction of new pipe parallel to an existing pipeline that has, or may become, a
constraint point. The feasibilty of looping a pipeline is primarily dependent upon the location where the
pipeline wil be constructed. Installng gas pipelines through private easements, residential areas,
63
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
existing asphalt, or steep and rocky terrain can greatly increase the cost to unjustifiable amounts when
compared with alternative enhancement solutions
The potential increase in system capacity by constructing a pipeline loop is dependent on the size and
length of new pipe being installed with tyical increases in capacity ranging from 50,000 - 250,000
therms per day on large, high pressure laterals. The cost for a new pipeline installation of this magnitude
is generally in the range of $5 - $12 millon.
Pipeline Uprate
A quick and sometimes relatively inexpensive method of increasing capacity in an existing pipeline is to
increase the maximum allowable operating pressure of the line, usually called a pipeline uprate. Uprates
allow a company to, maximize the potential of their existing systems before constructing additional
facilities and they're normally a low cost option to increase capacity; however, leaks and damages are
sometimes found or incurred during the uprate process creating costly repairs. There are also safety
considerations and pipe regulations that restrict the feasibilty of increasing the pressure in any pipeline,
such as the material composition, strength rating and location of the existing pipeline.
Compressor Station
Compressor stations are a third capacity-related option. They are typically installed on pipelines or
laterals with significant gas flow and the abilty to operate at higher pressures. Intermountain currently
has two such transmission pipelines for which the installation of a compressor station could possibly be
practical: the Sun Valley Lateral and the Idaho Falls LateraL. Regulatory and environmental approvals to
install a compressor station, along with engineering and construction time, can be a significant deterrent,
but compressors can also be a cost effective, feasible solution to lateral constraint points. Compressor
stations can be broken down into the following two (2) scenarios:
A single, large volume compressor can be installed on the pipeline when there is a constant, high flow of
gas. The compressor is sized according to the natural gas flow and is placed in the optimal location
along the lateraL. This type of compressor wil not function properly if the flow in the pipeline has a
tendency to increase or decrease significantly. This type of station can have a price range of $3 - $5
millon plus land, and a typical O&M cost wil be in the range of $150,000 - $200,000 annually.
The second option is the installation of multiple, smaller compressors located in close proximity or
strategically placed in different locations along a lateraL. Multiple compressors are very beneficial as they
allow for a large flow range, redundancy and the use of smaller and typically very reliable compressors.
These smaller compressor stations are well suited for areas where gas demand is growing at a relatively
slow and steady pace so that purchasing and installng these less expensive compressors can be done
over time. This "just in time" approach allows a pipeline to serve growing customer demand for many
years into the future while avoiding the single, rather large expenditure to purchase a larger station.
However, high land prices or the unavailabilty of land may render this option economically or
operationally infeasible. The cost of a smaller compressor station, excluding land, is estimated at $1.5 .
$2.5 milion with approximate O&M costs of $80,000 - $150,000 annually.
64
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
AVAILABLE AND POTENTIAL SYSTEM CAPACITY
ENHANCEMENTS
Throughout previous sections of the IRP it has been shown that due to system growth Intermountain
could possibly experience future capacity deficits. Through the use of a gas modeling system that
incorporates total customer loads, existing pipe and system configurations along with current distribution
system capacities, each potential deficit has been defined with respect to timing and magnitude. Where
any such deficit occurs multiple system capacity enhancements were evaluated and provided as inputs to
the optimization modeL.
The four identified Focus Zones that were analyzed under design conditions are: the State Street Lateral,
the Idaho Falls Lateral, the Sun Valley Lateral and the Canyon County Area. Each of these areas are
unique in their pipeline characteristics, and the optimization of each requires different enhancement
solutions.
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State Street Lateral
The State Street Lateral is a sixteen mile stretch of high pressure, transmission main that begins in
Caldwell and runs east along State Street into northern Boise. The Lateral is fed directly from a gate
station and is also looped with another pipe system from the south. Much of the pipeline is closely
surrounded by residential and commercial population that creates a difficult situation for construction
and/or land acquisition, thus making a compressor station or LNG equipment less favorable. A complete
review of the situation shows it is ideally suited to perform a pipeline uprate; where the additional
pressure at this location is obtainable and the Company has a chance to maximize the potential of its
existing facilties before investing in new. The up-rate can be performed in phases over multiple years
that provide increased capacity as actual growth is experienced, and the phasing wil minimize the length
of pipe that must be taken out of service at a time. As it turns out, the State Street lateral does not
exceed capacity, and therefore the model enhancement was not required for the five year projection of
this IRP. However, as available capacity is becoming increasingly tight on this lateral, Intermountain
believes it wise to continue to monitor and evaluate capacity in this area of its system. At a minimum, the
lateral is now defined, all of the related models include it for calculation purposes and this IRP has
already set up the necessary procedures to handle it in future IRP filings.J
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Canyon County Area
The Canyon County area has multiple pipelines of different diameters and pressures spread throughout
the area but there exists a single, undersized, bottleneck line which stands out as the weakest point in the
system. The best enhancement alternative for this situation is a pipeline loop that wil remove the current
bottleneck restriction. The loop wil be 7.8 miles long and wil be constructed of 8" high pressure pipe.
The line loop has a planned in-service date of PY2014 and wil increase the system capacity to 833,000
therms per day. The 2008 IRP estimated this project to be completed for PY2012 but growth estimates in
the current IRP show the need for increased capacity to occur two years later.
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Idaho Falls Lateral
Based on conclusions from the 2006 IRP, near-term IFL deficits have been remedied through the
installation of an LNG facilty, just south of Rexburg, which operates using portable LNG equipment. The
LNG facilty was installed in 2007 and the addition of a permanent LNG storage tank was installed for
PY2009, as indicated and planned for in the 2008 IRP. The onsite storage tank helps mitigate the plant's
reliance on tanker trucks transporting LNG supply to the site in times of high demand. A second LNG
tank is planned for installation in PY2012 for increased onsite storage as demand growth is anticipated.
The addition of the LNG facilty increased the maximum daily capacity of the IFL to 1,000,000 therms per
day.
65
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Sun Valley Lateral
The SVL is a long stretch of pipeline that has almost its entire demand at the far end of the lateral away
from the source. Obtaining land in close proximity to this load center is either very expensive or simply
unavailable. This tye of situation indicates that a compressor station installed on the lateral would best
maximize the performance of the existing line and allow for the installation to be a good distance away
from the concentrated load. Based on current lateral dynamics and project estimates, the 2008 IRP
stated that optimal timing of such an enhancement should occur prior to planning year 2011.
Since presenting the 20081RP, Intermountain has rebuilt the gate station that feeds the SVL and has
approved funding for the compressor station project. Land acquisition and permitting for the station is
underway with the local Bureau of Land Management, a reciprocating, natural gas engine and
compression unit is currently under construction and the housing facility and controls is in the engineering
and design phase. The project is scheduled for completion in early fall 2010; the resulting capacity
increase wil be available for planning year 2011. The total lateral capacity after this system
enhancement wil increase from 175,000 therms per day up to 204,000 therms per day.
66
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
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DISTRIBUTION SYSTEM MODELING
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A gas distribution system relies on pressure diferentials to move gas from one point to another. If the
pressure is exactly the same on both ends of a particular system gas is not flowing. When gas is
removed from some point on a system during the operation of natural gas burning equipment, the
pressure in the system at that point is then lower than the pressure upstream in the system. This
pressure diferential causes gas to move from the higher pressure point to the point of removal in an
attempt to equalize the pressure throughout the distribution system. The same principle keeps gas
moving from the interstate pipelines to the Utilty's distribution systems. When load demands exceed a
system capacity, the pressure at the far end of the system moves toward zero (or a specified minimum
pressure requirement), and the system essentially runs out of pressure. Therefore, it is important that
engineers design a distribution system in which the beginning pressure source from interstate pipelines,
compressor stations or regulator stations within the system are high enough and the transportation pipe
specifications are appropriate to create a feasible and practical pressure differential when gas
consumption occurs on the system.
Gas flow through a pipe falls under the engineering discipline of fluid mechanics. Due to the nature of
fluid movement there is a finite amount of natural gas that can flow through a pipe of a certain size and
length under a specified pressure; the laws of fluid mechanics are used to approximate this gas flow rate
under these specific and ever changing conditions. This process is known as "distnbution system
modeling." Ultimately, lateral and total system throughput under certain gas loading conditions, usually
pertaining to weather, can be ascertained. Maximum system capacity is determined through the same
methodology using peak degree day demands and contract loading of industrial customers.
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The modeling process is important because it allows an engineer to determine the capacity of various
distribution systems. For example, if a large usage customer is added to a distribution system the
engineer must evaluate the existing system and then determine whether or not there is adequate capacity
to maintain that potential new customer along with the existing customers. 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 customer
growth. Furthermore, existing system capacities can be evaluated using the model by increasing growth
in prospective areas throughout the system until pressure loss within the system becomes unacceptable.
In order to identify the maximum capabilty of all sections of the distribution system, the Company utilzes
gas modeling software to ascertain maximum system throughput under the various demand scenarios.
Comparing these flows against pipeline capacities identifies the magnitude and timing of potential
distribution system deficits.
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Modeling by Town
Intermountain utilzes a gas network analysis softare program created and supported by Advantica, Inc.
(recently acquired by Acquired by Germanischer Lloyd) to model all sizes of distribution systems. The
software program was chosen because it's reliable, versatile, and able to simultaneously analyze very
large and diverse pipeline networks. Within the software program, individual models have been created
for each of Intermountain's various distribution systems including high pressure laterals, intermediate
pressure systems, and distribution system networks.
The model of each system is constructed as a group of nodes and facilties. Intermountain defines a
node as a point where gas either enters or leaves the system, a beginning and/or ending location of all
pipe and non-pipe components, a change in pipe diameter or an interconnection with another pipe. A
facilty is defined in a system as a pipe, valve, regulator station, or compressor station; each with a user-
defined set of specifications. A model for a small town typically consists of approximately 100 - 300
nodes and 250 facilties, a medium town typically consists of 500 - 1,500 nodes and 1,200 facilties, and a
large city or area typically consists of 5,000 or more nodes and 5,000 or more facilties. The
67
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Boise/Meridian distribution model is the Company's largest and involves approximately 23,000 nodes and
26,000 facilties.
The software program allows our engineers to input and/or manipulate the gas load at an individual node,
selected specific nodes, or all nodes within a modeL. By using the forecasted loads within this integrated
resource plan Intermountain engineers can determine the most likely points where future constraints may
occur based on calculated pressure drops. Once constraint areas are identified, research and model
testing are conducted to determine the most practical and cost effective methods of solving the
constrained location. The feasibilty, timeline, cost and increased capacity for each theoretical system
enhancement is determined and then placed into a comparison analysis and used within the IRP modeL.
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68
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
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THE EFFICIENT AND DIRECT USE OF NATURAL GAS
Natural Gas And Our National Energy Picture
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According to the American Gas Association, in the United States natural gas currently meets 24% of the
nation's energy needs, providing energy to 64 millon American homes. The residential market uses 22%
of total U.S. natural gas consumption. Over 5,000,000 commercial customers also use natural gas for
their energy needs, consuming 15% of our nation's annual throughput. 200,000 industrial and
manufacturing sector customers use natural gas in their processes consuming 33% of the U.S. annual
total. And in another fast-rising sector, 500 electric-power-generating enterprises consume the remaining
30% of annual U.S. demand.
The simple reason for the widespread use of this energy source is: natural gas is the cleanest and most
efficient fossil fuel, period. Continued expansion of natural gas usage can help address several
environmental concerns simultaneously, including smog, acid rain, and carbon footprint.
Furthermore, 97% of the natural gas used in the United States comes from North America, where
supplies are abundant. And the 2.2-milion-mile underground natural gas delivery system has an
outstanding safety record, and is reliably capable of delivering natural gas, regardless of the weather.
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Thus, for all the right reasons, the demand for natural gas has risen, and with that, so has its price.
Wellhead gas prices have shown considerable volatilty over the last 10 years, reaching levels five times
greater than the prices in the mid 90s. Natural gas is stil very plentiful in North America, with an
estimated 60+ years supply at current consumption levels. Furthermore, when new "unconventional"
supplies such as coal bed methane are included in forecasts, U.S. natural gas supplies could be
extended several hundred years. What has happened, though, is that our nation's demand for natural
gas has caught up to the deliverabilty of the fueL. While there is enough production and delivery
capabilty to meet the demand, it now takes more drillng and more wells to maintain capacity. And with
this tightening of supply vs. demand, the price is up.
Now, more than ever, it is vital that all natural gas customers use the energy as wisely and as effciently
as possible.
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Natural Gas Equipment Efficiency
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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
effcient every 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. Residential gas usage dropped by
1 %/yr prior to 2000, and has dropped 2.2%/yr since 2000. As a result, the average household uses 32%
less natural gas thaa it did in 1980, thanks largely to the aforementioned efficiency improvements. And
by using energy wisely, consumers wil continue to use less, and therefore help control their energy costs.
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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
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natural gas, but is also improving the efficiency and cleanliness of existing applications. IGC has
participated in local GTI research and development projects, and wil continue that collaboration as the
opportunities arise.
Natural Gas Conservation Customer Education
Natural gas equipment efficiency makes economic sense in today's new energy era, and IGC wil
continue to encourage new residential and commercial technologies, as they become available.
On our website, ww.intgas.com. residential and small commercial customers can obtain detailed
information regarding energy conservation at home or their business. Large-volume/Industrial customers
have their own website from which they can obtain real-time gas consumption information.
Also at the website, customers can view our Energy Conservation Brochure, which was mailed to all our
+304,000 Core-market customers in January 2010. 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 bil paying and other services, IGC customers can also access their individual billng 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-effciency equipment when making their
equipment purchase or upgrade decisions.
We also continue to provide a detailed, 10-minute conservation tips video to our website. These videos
were produced by the Allance to Save Energy, and they give a wide variety of energy saving instruction
and advice, including do-it-yourself installation of insulation, storm windows, and weather-stripping, as
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2011 - 2015 Integrated Resource Plan
well as how-to's for natural gas conservation measures and practices. Customers can view all the videos,
or select segments that deal with particular conservation-minded tasks and instructions. We have also
provided DVD copies of the conservation tips video to community action agencies and others working to
counsel homeowners on wise energy usage. Wherever possible, our communications messages
promote the use of our website for such information.
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' 'Intermountain Gas Company's Industrial Website was designed to allow the industrial customer access to
the most up-to-date natural gas usage information at their location. The site is accessible via the intemet
using a specific logon name and password, making the information on each customer site-specific. It
contains a great deal of information useful to the large volume customer. They can access information as
to the different services and applicable tariffs.
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Viewing Consumption
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There are several tools to review, evaluate, and analyze the natural gas consumption at their specific
facilty. The meter reads are taken hourly, and sent via radio communication to our Gas Control Center.
Once this information is in our system, it is available for viewing on the website. This is especially useful
in tracking and evaluating energy saving measures and new production procedures. History may be
downloaded as far back as January 1994 and all information is available on an hourly, weekly, monthly,
and annual basis.
IGC strives to keep this site in the most usable format for the customers, so a "feedback" button is also
included on the site to let us know how best to fulfil their needs.
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Intermountain's customer contact and marketing personnel are equipped to assist current and potential
customers with evaluating the advantages of installng high-efficiency gas equipment where possible.
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IGC personnel have participated in energy conservation seminars at the Boise Public Library, the Bureau
of Land Management, the Department of Environmental Quality, the Idaho Green Expo, and the J R
Simplot Energy Symposium. During these talks, the IGC personnel gave a brief outline of the energy
pricing situation, offered conservation tips including the installation of automatic setback thermostats,
turning down water heater thermostats, and the importance of regular furnace filter maintenance. IGC
hopes to continue this particular activity in the future.
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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 stil to this day, a high-efficiency (90%)
furnace conversion rebate.
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 has
provided financial assistance to the Idaho Department of Water Resources Energy Division and to the
University of Idaho Integrated Design Lab to further their respective energy efficiency research and
training.
The Gas Technology Institute (GTI) is our nation's leader in ongoing natural gas R&D, as well as the
deployment and commercialization of new gas efficiency technologies. IGC has participated in GTI R&D
projects, and will continue that collaboration as the opportunities arise. In the spring of 2010, GTI and
IGC conducted a natural gas usage and feasibilty study at two larger industrial plants along the Idaho
Falls LateraL. The main purpose of this study was to determine the feasibility of applying "Super Boiler
Technology" which has been developed by GTI with the support of the Natural Gas Companies across
the United States. The study has been completed although the decision to invest and move forward with
the installation of some or all of the technology is stil being studied. The various applications had
financial recovery just in gas and water savings ranging from 1.55 to 7 years.
IGC is a member of the Energy Solutions Center Renewable Energy Workgroup. IGC has worked with
the Idaho Office of Energy Resources to provide Idaho schools' gas consumption data to energy
consultants working to obtain ARRA Stimulus funds for the state's primary and secondary school facilties.
In the fall of 2007, IGC became an ENERGY STAR Utilty Partner. Through this partnership, we promote
energy effciency in the new and existing residential markets via the encouragement of high-efficiency
ENERGY STAR appliances and equipment, as well as ENERGY STAR building practices for new single-
family and multi-family dwellngs. Our development of our policies and actions in this area is ongoing.
During 2009, IGC assisted the Governor's Office of Energy Resources in devising and planning the
implementation of the State Energy Efficient Appliance Rebate Program (SEEARP). SEEARP wil
distribute Federal Stimulus dollars to residents replacing older, less-efficient appliances with ENERGY
STAR equipment.
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
Aside from technical improvements in equipment efficiency, and conservation-minded customer behavior,
one overriding factor in 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 electric generating capacity becomes more constrained in the Pacific Northwest, additional generating
capacity wil primarily be natural gas fired. While development of additional hydro or coal-fired generating
facilities may be nearly impossible, those already in place with continue to operate a generally full
capacity for many years to come. Direct use wil mitigate the need for future generating capacity. If more
homes and businesses use natural gas for heating and commercial applications, then the need for
additional generating resources wil be forestalled. And at times of excess capacity, water storage
normally used for generating power, can be released for additional irrigating, aquifer recharging, fish
migration, and navigation uses.
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This more efficient, direct use obviously translates into a much lower carbon footprint.
First, let's look at coal-fired electricity, which makes up a sizeable portion of our region's power supply:
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Coal-fired, sub-critical steam power plants such as Jim Bridger are 40% efficient at best (a 40% heat
rate). The typical sub-bituminous coal used there has a heat-content of 18 milion Btu's per ton (9,000
Btu's per pound). When burned, this ton of coal produces over 3,700 pounds of C02 into the atmosphere
(1.85Ibs of C02 per pound of coal burned). At the facility's 40% heat rate, for each kilowatt-hour (3,413Btu's) of electricity produced, 8,532.5 Btu's worth of coal, or about .948 of a pound of coal must be
burned. So, 1 kWh of electricity from Bridger emits 1.75 Ibs of C02. To deliver the same amount of
energy to the natural gas direct user (3,413 Btu's), requires .03413 of a therm of natural gas, emitting .41
of a pound of C02 when burned. So, natural gas used directly instead of coal-fired electricity has a 76%
smaller carbon footprint than the electricity from a coal-fired plant.
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Now, let's consider natural gas powered electrical generation plants:
Natural gas fired combustion turbines like Danskin, are generally 60% efficient at best. Furthermore,
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-effciency natural gas
furnaces are rated at up to 96% efficiency. New gas water heater efficiency standards provide for 60% to
80% efficiency. In terms of the carbon footprint, a therm of natural gas (100,000 Btu's) delivered and
burned at the user source emits roughly 12 Ibs of C02 into the atmosphere. The equivalent amount of
electricity, 100,000 btu's, or just under 30 kilowatt hours delivers emits roughly 24 Ibs of C02, again
considering a 60% generating plant heat rate and 10% transmission line losses. So, in this case, direct
use of natural gas, where possible, has a 50% smaller carbon footprint than electricity from a natural gas-
fired plant.
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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 C02 emissions spread out
over a far wider airshed. This direct, and therefore, more-efficient natural gas usage wil 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 98% penetration rate along our service
mains, is a prime of example the direct use of natural gas, where possible.
To ilustrate the significant role that IGC plays in southern Idaho's total energy picture, IGC has over
275,000 residential customers. The average annual therm usage of an IGC space-heating-only customer
is 560 therms. That equates to a total residential therm usage of approximately 154,000,000 therms in a
year. If the total was used at the Federal efficiency minimum of 78%, then (150,000,000 X .78 =
120,120,000 therms X 100,000 Btu's/therm) or 12,012,000,000,000 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% efficient electric resistance
heat efficiency, this means that the IGC residential space-heat customers would use the equivalent of
(12,012,000,000,000/3,412) or 3,520,515,826 kilowatt-hours in a year to heat their homes. This is the
same as 3,520,516 megawatt hours of power saved, year in, year out. According to their 2008 Annual
Report, website, Idaho Power's total annual residential megawatt hour sales for 2008 were 5,297,000. If
the aforementioned 275,000 IGC residential customers were using electric space heat, Idaho Power's
total residential sendout would rise to 8,817,516 mWh, a 66% increase, requiring considerable additional
generation and transmission facilities.
:.1 In peak terms, if these 275,000 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 2,292 megawatts. Again, according to their website, Idaho Power Winter recently
experienced a 2008 winter peak load of 2,464 megawatts. Without the direct use of natural gas to heat
these 275,000 homes, Idaho Power's winter peak load could reach 4,756 megawatts, a 93% increase!
This additional 2,292 megawatt peak load would be the equivalent of nine 250 megawatt natural gas-fired
electric generating facilities all running at full throttle. This would probably also require a substantial
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2011 - 2015 Integrated Resource Plan
increase in transmission facilties to handle this peak load, since it would be well above the Idaho Power
Summer 2008 peak of 3,214 megawatts.
In terms of recently-shed electric load, just since 1991, IGC has converted over 27,500 residential electric
heating customers to natural gas. Using the space heating consumption rates shown above, these gas
conversions save about 350,000 megawatt hours of residential sendout per year. In winter peak terms,
using the "1/3 operating simultaneously" example in the paragraph above, 229 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. 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 significant relief to
the ever-growing hot weather electric demand. IGC has over 215,000 RS-2 (space and water heat)
customers. If, instead these were 215,000 electric water heaters each rated at 9,000 watts, or 9kW, this
would amount to 1,935 megawatts of total load. If this total amount was treated as shifted or curtailed,
per the Utah Power and Light irrigation load control credit rider of some years ago, the credit value would
have ranged from $1,857,600 in September to $4,334,400 for July. But the summer water heating load
curtailment and shifting provided by the IGC water heater customers has come at no cost to electric
utilties or their customers.
Lost And Unaccounted For Natural Gas Monitoring
As part of an ongoing commitment to the efficient use of natural gas, Intermountain Gas Company has
been pro-active in finding and eliminating sources of lost and unaccounted for (LUAF) natural gas. As the
name suggests, LUAF is the difference between volumes of natural gas delivered to Intermountain's
distribution system and volumes of natural gas biled to Intermountain's customers. Intermountain has a
standing inter-disciplinary team that reviews the LUAF audit processes currently in place, investigates
potential sources of LUAF, and takes remedial action as needed to continue to keep Intermountain's
LUAF levels low.
Billng and meter audits are important processes that Intermountain has established to address LUAF.
Billng audits to identify Low Usage and Zero Usage are performed with each billng cycle. Low Usage
Reports are used to compare biled consumption against that same customer's historical usage patterns.
If the current month's biled consumption appears low in relation to historical usage patterns, the account
is flagged. A courtesy phone call is then made to determine if there is a valid reason for the lower-than-
normal usage, or a check-for-dead order is generated for the following day and a service technician is
dispatched to field test the meter for functionality. Zero Usage Reports help to identify those meters
where usage is arguably taking place, but not registering on the meter. On those accounts that are not
documented as being "off" by the system, a check-for-dead order is generated and a service technician is
dispatched to field test the meter for functionality. Reports are also generated that review biled
consumption for a given meter size. There should arguably be a correlation between the customer's
biled volumes and the size of the meter installed to serve that customer. These types of correlated
audits sometimes identify malfunctioning meters and at other times identify a problem with the
programming in place that translates metered consumption to biled consumption.
Intermountain also compares on a daily and monthly basis its telemetered usage versus the metered
usage that Northwest Pipeline records. These frequent comparisons enable Intermountain to find any
material measurement variances between Intermountain's distribution system meters and Northwest
Pipeline's meters.
Meter audits are also an important tool in keeping LUAF levels low. Intermountain conducts regular
sampling of its meters to test for accuracy. A rotation plan is developed by applying the MIL 1 05D
standard for sampling to the eligible familes of meters in service. Sample meters are pulled from the field
and brought to the meter shop for testing. During testing, meters are checked for registration accuracy
and consistency of measurement between the mechanical meter index and the ERT unit. The results of
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this testing are evaluated by meter family to determine the pass/fail of a family based on sampling
procedure allowable defects. If the sample audit determined that the accuracy of certain batches of
purchased meters was in question, additional targeted samples would take place and any necessary
follow up remedial measures would be taken.
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In addition to these regular meter audits, Intermountain also identifies the potential for incorrectly sized
and/or type of meter in use by our larger industrial customers. Some industrial customers consume
natural gas differently over time as the economy changes, the customer institutes plant and equipment
improvements, or conservation measures are implemented. A meter size and/or type which may have
once been warranted at the customer's premise may no longer be applicable and a change in installed
meter size and/or type might be necessary. Many of Intermountain's large industrial customers have
remote measurement devices installed at their premise which faciltate a monthly comparison to the biled
volumes as determined by the customer's meter. If a discrepancy exists between the two measured
volumes, remedial action is taken.
Also related to meter audits, and in conjunction with the billng audits previously noted, Intermountain
works to ensure billng accuracy of newly installed meters. A Service Tech (different from the Service
Tech that installed the meter) performs an audit of the delivery pressure and drive rate of a newly
installed meter as it relates to the customer and meter manufacturer requirements. Any corrections are
made prior to the first bil going out.
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On a regular and programmed basis, Intermountain technicians check Intermountain's entire distribution
system for natural gas leaks using sophisticated equipment that can detect even the smallest leak. When
such leaks are identified, which is very infrequently, remedial action is immediately taken. Unfortunately,
human error by an outside contractor or even a home owner sometimes leads to unintentional damage to
our distribution system. When such a gas loss situation occurs, an estimate is made of the escaped gas
and that gas then becomes ''found gas" and not "lost gas".
Audit Results
Intermountain continues to monitor LUAF levels and looks for additional opportunities keep its LUAF rate
among the lowest in the natural gas distribution industry.
Conclusion
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Ever-increasing and more pervasive energy standards and practices wil continue to improve the energy
efficiency of Intermountain Gas Company's customers. Intermountain wil continue in its active role
promoting the wise and efficient use of natural gas and in carefully monitoring LUAF levels. The wise,
direct use of natural gas in the coming years wil help keep overall energy costs down in southem Idaho,
help protect the environment, and ensure ample, lower-cost electricity for its many other valuable uses.
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INTERMOUNTAIN GAS DEMAND-SIDE MANAGEMENT PROCESS
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¡In 2007, IGC began an evaluation of natural gas efficiency and conservation opportunities. The analysis,
selection, and potential deployment of such measures is known as Demand-Side Management, or DSM.
The purpose of this process was two-fold: 1) to ascertain whether achievable and economically viable
DSM could provide a reliable resource in IGC's peak-load management, and 2) to faciltate year-round
improvements in natural gas usage.
DSM includes behavior modification, building-envelope improvement measures, and higher-efficiency
natural gas equipment. DSM measures are tyically grouped into two categories, base load resources
and heat sensitive resources. Base load resources are those measures that displace the need for gas
supply requirements day in and day out regardless of the weather, such as high-efficiency water heaters.
Heat Sensitive DSM are those measures whose therm savings increase the colder the weather. For
example, a high efficiency furnace wil lower therm usage in the winter months when the furnace is
utilzed the most and wil provide little if any savings dunng the summer months when the furnace is often
turned off. Examples of heat sensitive DSM measures include walllfoor/ceilng insulation, high efficiency
gas furnaces, and improvements to duct work. These tyes of measures wil tend to offset more of the
peaking or seasonal gas supply requirements which are typically more expensive than base load
supplies.
The Intermountain DSM process consists of four steps:
1. Establishment of broad DSM Objectives
2. Ascertain and address a full spectrum of DSM opportunities/measures
3. Perform an assessment of potential DSM programs
4. Select and design programs for pilot testing and later, possible deployment
DSM Objectives
. Provide customer service
. Accommodate high effciency and off-peak load growth
. Limit the need for new staffing resources
. Maintain competitive position as low-cost energy provider
. Provide environmental benefits
. Focus solely on the most cost-effective DSM measures
Addressing a full spectrum of DSM Opportunities
The first task in assessing DSM opportunities is to analyze and determine costs and the associated
energy savings for the DSM measures. Evaluating specific measures involves ranking measures by
levelized cost per therm saved. Future years' therm savings are discounted over the life of the measure
for proper comparison to other DSM measures and supply side resources.
A total resource cost (TRC) approach is used to evaluate cost-effectiveness of all DSM resources. The
TRC method compares total net costs of DSM resources to the total net cost of supply side resources
displaced. A program or measure is cost-effective if the present value of energy savings and non-energy
benefits derived from installng that measure is greater than the total resource cost (TRC) of the program
or measure, Non-energy benefits may include, for example, water savings from low-flow showerheads
and higher efficiency clothes washers or reductions in maintenance costs.
IGC had performed previous DSM analysis in the early- and mid-90s. Through that, we gained an
understanding of the various factors and processes involved, and participated in regulatory procedures
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and evaluations. At the conclusion of the process then, it was not clear that DSM made sense for IGC for
a variety of reasons and externalities. As a result, the IPUC ordered IGC not to deploy any Core-market
DSM programs.
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But at the same time, interruptible transportation contracts with certain Industrial customers provided the
least-expensive and most quickly deployed DSM for peak-load management. As previously mentioned
Intermountain continued to encourage high-efficiency equipment and practices however the company did
not offer any formal DSM programs, since most measures were not deemed cost effective at that time.
However, with the many improvements in technology the company believed that a new and updated set
of references was necessary.
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To this end, IGC engaged Navigant Consulting, of Philadelphia, (Navigant) to assist in the discovery and
evaluation of the full spectrum of DSM opportunities. An important requirement of Navigants work was
that only established, natural gas DSM measures being employed by other gas utilties were to be
catalogued and evaluated.
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Assessment of Potential DSM Programs
IGC provided Navigant with customer segmentation and distribution data, service-area market
assumptions, and other pertinent data. Navigants work was very thorough, and various measures were
listed, along with their various costs, market deployment potential, potential peak and annual gas savings.
DSM programs listed were also broken down by their market potential in the geographically-specific
laterals, as described elsewhere in the IRP.
The programs listed in Navigants work included ductwork improvements, appliance efficiency upgrades,
insulation improvements, ventilation upgrades, improved windows, and other building envelope
measures.
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Advanced Efficiency - Condensing Furnace AFUE--96
Air-to-Air Heat Exchangers
Below Grade Insulation (R-10)
Duct Insulation (R-8)
Duct Repair and Sealing
Green Roof
Drain Water Heat Recovery (GFX)
Energy Star Clothes Washer (MEF=1.8)
Energy Star Dishwasher (EF:i.58)
Faucet Aerators (2.5 GPM)
High Efficiency Storage Water Heater (EF:i.64)
Hot Water (SHW) Pipe Insulation (R-4)
Integrated Space and Water Heating - Premium Storage
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Low-Flow Showerheads 2.5 GPMJ
High Effciency Condensing Furnace (AFUE =90)
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High Efficiency Windows (U:i.35)
Insulated Exerior Entry Door
Insulation-ellng (R-38)
Insulation-Roor (R-25)
Insulation-Rim Joist (R-10)
Insulatlon-Wall2x4 (R-13)
Integrated Space and Water Heating - Condensing Furnace
(AFUE =90)
Leak Proof Due Fittings
NW ES Homes - Site Built
PTCS Aerosol-Based Duct Sealing
Whole House Air Sealing
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Screening and Ranking i
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For planning purposes, the company chose to first consider programs that would not duplicate other
programs, would not be redundant with regard to codes or other regulations, and would provide truly
additional energy savings. Cost-effectiveness was important, but the measures selected had to impact
the greatest number of customers, and their most significant gas usage.
Measures such as building envelope improvements (windows and insulation) wil have a less direct
impact on natural gas usage. It's assumed that a more tightly-sealed, better-insulated home wil use less
gas for space heat, but the gas-usage impact of such an upgrade is going to be more variable, and a little
harder to quantify. On the other hand, appliance efficiency upgrades have a more direct usage impact
which is more readily quantified. Furthermore, appliance efficiency upgrades - namely furnace and water
heaters - fit in with IGC's ENERGY STAR Utilty Partner efforts.
DSM Program Selection and Design
IGC's potential DSM programs target the residential market segments consisting of new construction,
existing homes who are switching to natural gas from other energy sources ("conversions"), and our
existing customers. There are some geographical particulars with regard to weather and our system
capacity. As a consequence, DSM approaches and programs wil be devised and deployed within this
framework.
As part of this evaluation the company is mindful of two things that can affect the cost effectiveness of
DSM programs, those are the impacts of free riders and the impacts associated with lost opportunities.
Free riders are those individuals that would have undertaken some form of conservation action even if a
program had not existed. Measuring free rider impacts makes program evaluation dificult since it requires
information on a hypothetical situation that, by definition, wil never be observed. Lost opportunities assumes
that the opportunity to install cost-effective conservation measures occurs only once in the life of a home,
office, or industrial plant. If the potential cost-effective conservation is not installed atone time, future DSM
opportunities may be lost. For example, once a customer installs a new furnace or water heater, it is unlikely
that they would replace it for a more efficient model until the end of its life cycle. Therefore for equipment with
long-lives it is important to influence the customer's choice for the more efficient model at the time of initial
purchase since it is likely 18 to 20 years before such an opportunity would exist again.
New Construction
As previously mentioned, building techniques and codes, and improved appliance technology have
resulted in homes using 32% less gas than in 1980. Additional upgrades, such as ENERGY STAR,
typically provide, monthly utilty cost savings that outweigh the additional monthly mortgage payment to
cover their added cost. Therefore, new-home buyers already have a financial incentive to include higher
energy efficiency features in their new home.
Since these new-construction efficiency measures already offer a significant financial incentive, IGC
proposes to continue its promotion of high-efficiency new construction in our advertising, builder
association participation, and through our ENERGY STAR Utilty Partner activities. This market-based
approach makes the most sense in the new-construction arena, as the company is concerned that if it
was to provide an incentive rebate program that many of the consumers could ultimately be free-riders.
Conversions
In order to capture the higher-efficiency opportunity when a homeowner has decided to convert to natural
gas, the company wil continue to offer the $200 rebate when that homeowner installs a 90%-or-greater
efficiency natural gas furnace at the time of conversion. According to the Navigant study, the typical high
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2011 - 2015 Integrated Resource Plan
effciency furnace installed in an existing home saves approximately 82 therms on an annual basis and
approximately 1 .5 therms on a peak day with a levelized TRC of approximately 63 centsltherm and from a
Utilty Cost (UC) perspective the program is approximately 21 cents/therm saved.
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The company is also evaluating offering a $30 rebate when a homeowner decides to convert to a natural
gas water heater from another energy source, and installs a .64-or-greater energy factor (EF) gas water
heater. According to the Navigant study .64 or greater water heaters provide approximately 15 to 21
therms savings per year and the levelized TRC ranges from 38 to 45 centsltherm saved. From a utilty
cost perspective, the $30 rebate would result in program costs of approximately 21 cents/ therm saved.
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IGC is evaluating offering a $200 rebate when an existing customer replaces a below-90% efficiency
natural gas furnace with a 90%-or-greater efficiency natural gas furnace. Similar to the conversion
market, the company is focused on avoiding a lost opportunity should the customer choose to remain with
a lower efficiency modeL. Estimated annual therm savings and costs are the same as those identified
above with the conversion market, and the TRC and UC are estimated to be 63 cents/therm and 21
centsltherm respectively. The company wil also be evaluating a $30 rebate when an existing customer
replaces a .59-or-below EF natural gas water heater with a .64-or-greater EF natural gas unit. Such an
incentive would result in approximately 15 to 21 therm savings per installation at a UC of 21 cents/therm
saved and a levelized TRCI of approximately 38 to 45 cents/therm saved.
Implementation
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The additional programs - water heater conversions, and the furnace/water heater upgrades would be
deployed in a pilot program on the Idaho Falls lateral in Calendar 2011. This pilot approach wil allow for
evaluation of the market acceptance of the particular programs, and the opportunity to adjust the
programs and develop effcient administration routines. Additionally, focusing on the Idaho Falls lateral
could provide additional value due to the capacity constraints identified earlier in the plan. Expansion
could come later, based on the pilot program's results. The furnace conversion program is already in
place, company-wide and the company continues to promote the installation of high-effciency and
ENERGY STAR equipment.
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79
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
RESOURCE OPTIMIZATION
Introduction
Intermountain's IRP utilzes an optimization model that selects resources over a pre-determined planning
horizon to meet forecasted loads by minimizing the present value of resource costs, The model
evaluates and selects the best mix of supply and transportation resources utilzing a standard
mathematical technique called linear programming.
This summary wil first describe the model structure and its assumptions in general. Initial results wil then
be discussed.
Data Components of the Model
The optimization model has four basic data components:
. Demand forecast (Exhibit 4 No.4, Table 1)
. Supply resources (Exhibit 4 No.4, Table 2)
. Transportation capacity resources (Exhibit 4 No.4, Table 3)
. Supply prices (Exhibit No.4, Table 4)
Underlying these three components is a model structure incorporating demand side management,
transport capacity (arcs) and demand areas (nodes) which mirror how the Intermountain Gas delivery
system contractually and operationally functions (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 and
auditable. Since Intermountain's model evaluates gas supply and capacity additions over a 5 year period,
the model was designed so that only the major elements are recognized.
This is in distinction to a dispatch model that needs to balance every detail precisely and so requires a
level of detail that is fully representative of all daily system requirements. For this reason, a more
simplified structure is utilzed in the Intermountain's IRP modeL.
Model Structure
In order to develop a basic understanding of how gas supply flows from the various receipt points to
ultimate delivery to the Company's end-use customers, a graphical map of system flows was developed.
(Figure 1 on the following page shows a graphical map of the demand and supply nodes and transport
arcs of the IRP model). Note that the map shows four (4) major receipt areas including Sumas, Stanfield
(which also shows that supplies sourced from Alberta are delivered into Northwest via three "Upstream"
pipelines), and two different areas where gas supplies are received from the Rockies. Supplies from
those receipt areas are then assumed to be delivered and aggregated at the IMG pool where they are
allocated to be delivered to the appropriate lateral/area, or demand nodes, on Intermountain's system.
Those map symbols were then converted into a mathematical system of tables so that a system of
numbered arcs and nodes reflect physical locations on the map. The resultant set of numbered arcs and
nodes are shown on Tables 1 and 2 on the following page.
80
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Figure 1
Graphical System Map
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Table 1
Demand and Supply Nodes
Area # 1 2 3 4 5 6 7 8 9 10 11
Name Sumas Stanfield North South NIT IMG All Canyon Idaho Sun State
Green Green Pool Other County Falls Vallev Street
Table 2
Demand and Supply Nodes and Applicable Transport Arcs
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1 Sumas 1 IMG 6
2 Stanfield 2 IMG 6
3 N. Green 3 IMG 6
4 S. Green 4 IMG 6
5 NIT 5 Stanfield 2
6 IMG 6 All Other 7
6 IMG 6 Canyon 8
6 IMG 6 Idaho Falls 9
6 IMG 6 Sun Valley 10
6 IMG 6 State Street 11
AreaIode From Area/Node To
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Load Duration Curve Chart
As previously discussed, to simplify modeling the Load Duration Curve (LDC) was aggregated into 12
homogenous periods with similar load characteristics and then loads for each of those period loads were
averaged. The resultant demand curve represents load changes over the entire year but with a minimum
of data points. The figure below depicts an LDC aggregated into those homogenous groups. Each
aggregated "level" reflects one period modeled in the optimization model although the model stil
recognizes the number of days in each period and computes the total flow per period. The bold horizontal
lines provide an example of how the LDC looks after the aggregation and averaging is performed. The
optimization model utilzes five separate LDC's so as to separately represent the Sun Valley, Canyon
County, Idaho Falls, State Street and Total Company demand characteristics.
Intermountain Gas Company's 2011-151RP
Sample Design Daily LDC vs. Aggregated LDC (Dktherm)
500,000
450,000
400,000 \
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350,000 t
300,00
a i ..
250,000
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~ 'O150,000 - -¡ ..
100,000
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1 16 31 46 61 76 91 106 121 136 151 166181 196 211 226 241256 271 286301 316331 346361
Chronological Days
I- - Daily LOC ''--.'-' Aggregated LDC I
The model is also programmed to recognize that Intermountain must provide gas supply and both
interstate and distribution transportation for its core market and LV -1 customers but only distribution
capacity for its T-3, T-4 T-5 customers. Because Intermountain is contractually obligated to provide a
certain level of firm transport capacity for its transports, the industrial demand forecast for these
customers is not load-shaped but reflects the aggregate firm industrial CD for each class by specific node
for each period in the LDC.
Supply Resources
Resource options for the model are of three types: supply resources, storage contracts and DSM inputs
and all are utilzed in a similar manner. All resources have beginning and ending years of availability,
period of availabilty, period and annual flow capabilty and a peak day capabilty. Supply resources have
price/cost information entered in the model over all points on the load duration curve for the study period.
Additionally, information relating to storage resources includes injection period, injection rate, fuel losses
and other storage related parameters are included.
Each resource must be designated from a supply area. One advantage of Citygate supplies, certain of
the storage facilities and DSM is that they do not utilize any of Intermountain's existing interstate capacity
82
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
as the resource is either sited within a demand area node or are bundled with their own specific redelivery
capacity. Supply resources from British Columbia are delivered into the Northwest system at Sumas
while Rockies supplies are received from receipt pools known as North of Green River and South of
Green River. Alberta supplies are delivered to Northwest's Stanfield interconnect utilzing available
"Upstream" capacity. Each supply utilzes the appropriate transport arc(s).
'1
From a model perspective, the DSM resources are considered a subset of supply resources and fil
demand needs on the applicable node by offsetting other supply resources when the cost of such is less
than other available resources. These resources are assignable to a specific node and essentially offset
demand in the specified demand region. These resources have costs and resource capacity that was
determined by a separate DSM analysis performed by Navigant.
Transport Resources
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Transport resources are explicitly associated with arcs in the model which represent the flow of supplies
from specific receipt areas to Intermountain's IMG receipt pool called IMG for ultimate delivery into the
Company's demand nodes. Transport resources reflect contracts for interstate capacity, primarily on
Northwest Pipeline, but also for the three separate pipelines that deliver gas supplies to the Northwest
interconnect called Stanfield (because these pipelines operate in a serial fashion and have nearly
identical flow capabilties, for modeling purposes they are treated as one arc and are referred to as
"Upstream" capacity). There are also arcs reflecting each of the individual laterals or nodes (e.g. the IFL)
and for Total Company. For example, supply resources to be delivered from Sumas to Idaho Falls, first
must use the Sumas to IMG arc and from there flow from IMG to the Idaho Falls arc. Supplies such as
Rexburg LNG or DSM are already located on the Intermountain system at a specific demand lateral and
therefore do not require interstate pipeline transportation. The system representation recognizes
Northwest's postage stamp pricing and capacity release.
Transport resources have a peak day capabilty and are assumed to be available year round unless
otherwise noted. Transport resources can have different cost and capabilties assigned to them as well
as different years of availabilty. For example, different looping options for the Idaho Falls lateral are
available to the model at different periods to facilitate the flexibilty of timing decisions.
Model Operation
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The selection of a best cost mix of resources, or resource optimization, is based on the cost, availabilty
and capabilty of the available resources as compared to the projected loads at the nodes. 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. The model recognizes contractual take commitments
and all resources are evaluated for reasonableness prior to input. Both the fixed and variable costs of
transport, storage and supply can be included. The model wil exclude resources it deems too expensive
compared to other available alternatives.
The model can treat fixed costs as sunk costs for certain resources already under contract. If a fixed cost
or annual cost is entered for a resource, the model wil include that cost for the resource in the selection
process that wil influence its inclusion vis-à-vis other available resources. If certain resources are
committed to and the associated fixed cost wil be paid regardless of the level of usage, 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, wil be evaluated using both fixed and variable cost.
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The model operates in a PC environment. The various inputs are loaded via an Excel spreadsheet where
they are loaded and utilzed by PC linear programming software. The model is run by first launching the
optimization software, opening the Excel model containing all the appropriate scenario of demand,
supply, storage and capacity inputs (including all the correct prices) and callng up the correct constraint
model set. The optimization softare links the inputs to the constraint model, optimizes all resources to
the period demands. Once the model computes the best resource mix, they results are organized by a
set of macros that writes the output back into the same Excel model which helps to audit and evaluate the
model for reasonableness accuracy.
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Special Constraints
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As stated earlier, the model minimizes cost while satisfying demand and operational constraints. Several
constraints specific to Intermountain's system were modeled in the IRP modeL.
. Both LNG storage and DSM do not require redelivery transport capacity. Both SGS and LS storage
are bundled with firm delivery capacity; transportation utilzation of this capacity matches storage
withdrawal from these facilties.
. All core market and LV-1 sales loads are completely bundled.
. The T-3, T-4 and T-5 customer transportation requirements utilze only Intermountain's distribution
capacity.
. Traditional resources destined for a specific lateral node (e.g. IFL) must be first transported to the
IMG pool and then from IMG to the lateral node.
. Non-traditional resources such as mobile LNG that are designed to serve a specific lateral can only
be employed when lateral capacity is fully utilzed.
Model Results
The optimization model results for the Design Weather, Base Price and Base Growth scenario for the
years 2011 through 2015 are presented and discussed below. The results of the model are summarized,
for each demand scenario using the tables described below:
. Resource Usage Table (includes both period and annual flow)
. Storage Injection Table
. Transport Usage Table (includes both period and annual flow)
. Annual Cost Summary (includes supply and transport and total annual supply costs)
Exhibit No 4, Tables 5.1 through 5.5 presents the results for each year of the selected scenario. A
summary discussion for years 1 and 5 of each table is discussed below. The changes in model results
between years 2 through 4 are shown in detail in Tables 5.2 through 5.4 but a detailed discussion for
those years is not presented in this document.
Resource Utilzation - General
There are generally three types of supply resources; existing supply contracts, existing storage contracts
and incremental/spot contracts. Transport resources include both Northwest and Upstream capacities (to
bring Alberta supply to NWP at Stanfield) as well as the capacities for the four regional segments on the
Intermountain system. The following sections wil summarize the utilzation of each type of supply and
transport resource for the model years 1 and 5.
The Resource Usage Tables for the selected scenario is found on pages 1 - 4 of each respective Table 5
in Exhibit No.4, and provides usage information on the supply and other resources available to
Intermountain. Column 1 corresponds to the resource number. Column 2 corresponds to a resource
acronym, which the model utilizes for printouts. The next column identifies the arc to which the resources
are delivered to Northwest (or upstream arc where applicable). For example, the Sum-A resource is
delivered to NWP at Sumas.
The model selects the best cost portolio 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 and it wil not take inexpensive spot gas until all constraints related to term gas or storage
84
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
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are fulfiled). In order for the results to provide a reasonable representation of actual operations, all
existing resources that have committed must take contracts are assigned as "must run" resources. Other
incremental resources are evaluated only by variable cost. The Company's minimal commitment for
summer must-take supplies means that those supplies do not exceed demand. In the real world, having
excess summer supplies results in sellng those volumes into the market at the then prevailng prices
whereas the model only identifies those volumes and cost thereof.
Another important assumption relates to the "Fil" options. Fil resources provide intellgence as to where
and how much of any deficit in any existing resource exists; the model treats them economic commodities
meaning that availabilty is dynamic up to its maximum capabilty The model can select available Fil
supply at any node, for any period and in any volume that it needs to help fil capacity constraints. To
ensure that the model provides results that mirror reality, these supplies have been aggregated into peak,
winter, summer and annual 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 normally based on
the monthly spot index price, no attempt has been made to develop fixed pricing for Fill resources but
each such resource includes a reasonable market premium if applicable.
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The storage injection table provides the amount of resources injected into the various storage facilties for
which Intermountain retains direct control. Reflective of the real-world cycling constraints, storage may
only be withdrawn in the peak and/or winter periods and injections may only occur in summer periods.
The period injection rate multiplied by the period DTH capabilty, including any loss factor, results in the
net period DTH injected by period.
The transportation capacity usage table provides the same type of information as the supply usage table
and is similarly formatted. 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. The usage rates are shown both by period and by total annual flow.
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Again, the incremental transportation "Fil" contracts are treated as "commodity" resources in that the
model can utilze this capacity in the period it needs it, but only in limited volumes subject to maximum
and minimum constraints. The current assumption of on-demand Fil 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. As most available capacity found in today's world comes via capacity release rather than
pipeline expansion, any new capacity is assumed to be available via capacity release.
1
Transportation resources fall into four categories: existing interstate (both for Northwest and Upstream
pipelines) and storage redelivery capacity, on-system lateral capacity, and incremental capacity
resources. The existing resources are labeled ES on either NWP or Upstream. Incremental interstate or
lateral resources are made available as inputs when prior evaluation, or selection of a Fil resource,
determines the need for some alternative. Selection of any such resource demonstrates that any deficit
would be best satisfied by implementation of that resource over any other available alternatives.
Resource Optimization Summary Results
While Intermountain has completed runs for all demand scenarios discussed in this document, all of the
following year-by-year comparisons are based on the Design Weather, Base Price, Base Growth scenario
also referred to as the "Base Case" run.
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85
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Design Base Case - Year 1 (see Exhibit No.4, Table 5.1)
Supply Resources
The existing supply resources (contracts 2 - 7 and 9) have usage rates of 100% for all applicable periods
meaning that these resources are utilzed at maximum capacity in all demand periods (the resources with
that are empty reflect resources that were previously utilzed in prior IRP's but not for this IRP. The
positions have been left in place with null data for ease of model d~ta loading and auditing and can be
considered placeholders for use in future IRPs.
Resources 25-28 represent capacity release volumes which Intermountain has provided for certain of its
distribution-only industrial customers while resources 29 and 30 reflect the requirements of transport
customers who provide their own interstate capacity and commensurate amount of supply at the IMG
Pool. These industrial resources are run at maximum for every period to ensure that the Company
reserves capacity for these customers at contractual levels. Resources 1 and 63 are similar in that they
are also delivered at the IMG Pool but these deliveries are for the Intermountain's sales customers but
they have the advantage of not using any of the Company's existing interstate capacity.
A significant amount of spot-type supply from all supply basins (Resources 41, 45, 46, 51 and 55) is
utilzed during periods 1 - 12. Rockies spot (45 and 46) are utilzed all year long while Sumas and Alberta
supplies are needed only during periods 1 - 9. These resources have prices tied to the applicable basin
index prices (calculated from Nymex Futures prices plus or minus the appropriate basin differential) and
are selected using available existing firm capacity before adding incremental capacity. Note that the Idaho
Falls satellte LNG is utilzed in periods 1 and 2 and fully fils the "deficit' on that lateraL.
Storage Resources
The JP and Clay Basin facilties (resources 14 and 18 - 20) are fully utilzed, or nearly so, in periods 1 - 8
and are completely withdrawn on an annual basis. The Plymouth LS peaking contracts (resources 16 and
17) are utilized for periods 1 - 5 only (the five coldest days) and approximately 27% of the total inventory
is withdrawn. Intermountain's LNG facilty, it final peaking resource, shows no withdrawal in any period.
As loads continue to grow, further utilzation of these liquid storage facilties can be expected.
All storage except LNG is fully withdrawn during the peak day. 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 facilty. Although the real world storage cycle can overlap years (e.g. injections
could actually occur in a subsequent year), this model was designed a closed system where net injections
must equal net withdrawals in any given year.
The satellte storage facilty on the IFL shows total withdrawals of 9,308 Oktherm or approximately 10% of
the total inventory.
DSM
The pilot program OSM resource is fully utilzed on the IFL although the total therm savings in year 1 is so
low that it rounds to a number below one Oekatherm in every period.
Capacity
All existing NWP firm capacity is fully utilized for the peak period, which implies that absent any additional
storage withdrawal capacity, Intermountain might require incremental capacity as future loads grow. No
deficits occur on any the constraint zones on the distribution system.
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Annual Cost Summary
The last three, pages of each Table 5 in Exhibit No.4, summarizes the variable cost of the supply and
capacity resources as selected by the modeL. Per Table 5.1, the grand total of all 2011 discounted
variable resource costs are $240.6 milion.
'~'l Design Base Case - Year 5 (see Exhibit No.4, Table 5.5)
Supply Resources
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The existing supply resources (contracts 1 - 8) are stil fully utilzed. The industrial Resources 25-28 are
now at zero reflecting that capacity release to these customers had been discontinued while resources 29
and 30 stil show maximum deliveries from the distribution only customers.
A significant amount of spot-type supply from all supply basins (Resources 28, 41, 46, 51 and 55) is
utilzed during periods 1 - 12. Rockies spot (46 and 60-62) are heavily utilized all year long including the
summer months.
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Storage Resources
The JP and Clay Basin facilties (resources 14 and 18 - 20) are stil fully utilzed, or nearly so, in periods 1
- 8 and are completely withdrawn on an annual basis. The liquid storage at Plymouth, WA (16 and 17) is
used more heavily with total withdrawals at 442,223 Dktherms or 40% of the total inventory. While
Intermountain's LNG facilty stil shows zero withdrawals, remaining Plymouth peaking storage is within
18,000 Dktherms of being maxed out and this assumes no supply failures from any supplier of natural
gas or pipeline capacity. In the event of any such supply failure, Nampa is the only remaining resource
available.
All storage except Nampa LNG and about 18,000 of Plymouth LS is used on the peak day.
The satellte storage facilty on the IFL shows 68% of maximum withdrawal in period 1 and a total
withdrawal of 28,121 Dktherms over periods 1-3; no other IFL specific resources are needed. No other
fil-type resources are needed on any of the Company's laterals except for SVL capacity (see "Capacity"
below).
DSM
Again, all available DSM is utilzed in year, Peak day DSM totals just over 7 Dekatherms while the annual
therms savings total approximately 2,253 Dekatherms. The five-year total savings is 5,420 Dktherms.
Capacity
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All existing NWP firm capacity is fully utilzed for periods 1-6. Rockies capacity is at near 100% usage
through period 10 reflecting the projection of projection of lower gas supply prices. Stanfield is at full
capacity through period 8. The model selects approximately 14,000/day of incremental capacity. If the
model had no additional capacity available, it would have been forced to use nearly 100% of the
Company's liquid storage. No deficits occur on any the constraint zones but the SVL expansion is utilized
in periods 1-4; the peak usage is about 50% of its peak capabilty.
Annual Cost Summary
Per the last sheet of Exhibit No.4, Table 5.5, the grand total of all 2015 discounted resource costs are
$337.2 milion.
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Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
COMPARATIVE ANALYSIS 2010 IRP vs. 2008 IRP
Residential and Commercial Growth Forecast
The methodology used to calculate residential and commercial customers for the 2010 IRP is consistent
with that used in the 20081RP. However, customer growth in the 2010 IRP is forecast to be more
moderate than in the 2008 IRP, mainly due to the recession and the corresponding downturn in housing
construction. On average, the forecast annual growth from 2011 through 2015 is 27% less than that
which was forecast for the preceding 2009 - 2013 IRP. The current five-year customer growth is now
forecast at an annual rate of 2.2% compared to the previous IRP's 3.0%. The 2011 beginning customer
figure of 308,758 per the 2010 IRP is 8,588 customers lower than the 2011 projection of 317,346 found in
the 2008 Plan.
One major difference between the 2008 and 2010 IRP customer forecasts is the incorporation of an
additional IGC Distribution System segment in the analysis. This is the "North of State Street" Lateral
Segment, ("State Street") consisting of the area of Ada County north of the Boise River, bound on the
west by Kingsbury Road west of Star, and bound on the east by State Highway 21. The State Street
segment had previously been part of the "All Other Customers" segment in the previous IRP.
Usage per Customer with Design Degree Days
The method of calculating the design degree days in the 2010 IRP was largely the same as the method
used in 2008. Design weather was calculated for the newly added State Street Lateral area of interest
utilzing the same method used to calculate Design weather for the Total Company and other areas of
interest. For more information on design degree day calculations see "Heating Degree Days and Design
Weathet' on page 29.
The usage-per-customer calculations for the 2008 IRP were based upon data from 1989 through 2007.
The 2010 IRP filng makes use of two additional years of data and therefore includes data from 1989
through 2007. Price Elasticity was a significant explanatory variable in the non-peak month models in the
2008 IRP filng. In the 2010 filng, it has also become a significant explanatory variable in the peak month
models. Intermountain analyzed the Sun Valley and Idaho Falls Laterals in the 2008 IRP filing to identify
any differences in usage per customer for those two areas compared to the Total Company. In the 2010
IRP, Intermountain also included an analysis of the Canyon County and State Street Lateral areas of
interest. Intermountain again made refinements to the peak day usage per customer equation for the Sun
Valley lateral based on that analysis. A more detailed discussion of the 2010 Usage Per Customer
calculation begins on page 33.
Industrial Forecast
Energy conservation is a very high priority for industrial customers to maximize production and output in
order to stay competitive. The industrials must get the most production from their invested capital and
hold the line on prices. Many of Intermountain's customers are using the Intermountain Gas Industrial
Website to assist with this effort as they can immediately know whether a process adjustment or other
improvement is actually saving them energy.
The Customer Contract Demand (CD) forecast reported in this 2010 IRP is basically the same as
reported in the 2008 IRP. The overall usage, however, is approximately 8.5% greater in the 2010
forecast. This would indicate that the usage is spread over the year or at non-peak times. There is a
mixture of forecast increases and decreases across the market segments the sum of which shows a flat
usage forecast over the plan years. (See Attachment No.1, Tables 1.1 and 1.3).
88
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Load Duration Curves
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¡..J The total company Core market sendout forecast for 2011 ~2013 is lower than 2008's IRP by a range of
4.5% - 6.9%. The overall peak day sendout for the same period is slightly less at a 6.2% - 8.4% decrease
(See Attachment 1, Table 2.3). The 2010 IRP reflects no peak day firm delivery diferences for 2011,
2012 or 2013, Storage deliveries are projected to remain the same as identified in the 2008 IRP See
Attachment 1, Table 3.3). There are no occurrences where the projected peak demand exceeds peak
deliverabilty. (See Attachment No.1, Table 4.3).
"1 Idaho Falls LateraL. The 2010 IRP reflects a decrease in peak demand for 2011 ~2013 of between 7% and
9.4% when compared to the 2008 IRP (see Attachment No.5, Table 5.3). Due to reduced customer
growth forecasts, the peak day deficit projected occurrences decreased to 2 (from 4) from 2011 through
2013 from the 2008 IRP (See Attachment No.1, Table 6.3). Please note that these two occurrences do
not take into account that we have the Rexburg LNG facilty available to offset any deficits.,1
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Sun Valley Lateral. Peak loads decrease by 3.5% - 6% for years 2011-2013 when compared to the 2008
IRP. The fact that there is no growth in industrial CD highlights the decrease in Core market growth in this
region (See Attachment No.1, Table 7.3). There are the same numbers of days of deficit for 2011 (2)
and 1 less for 2012 and 2013 (2 and 3, respectively) when compared with the 2008 IRP. In 2011 there is
a planned compressor station which wil add additional capacity, eliminating any peak deficits (See
Attachment No.1, Table 8.3).
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Canyon County. Peak load usage waned greatly compared to 2006 IRP projections. In fact, the 2010
IRP showed a reduction in peak day usage by approximately 10.3% on average when compared to the
20081RP. Several system enhancements such as mainline looping and more available throughput at the
interconnection between Intermountain and Northwest Pipeline account for the increased capacity
projections for 2011. Another interesting note is that in the 2010 IRP there are no projected deficits (See
Attachment No.1, Table 9.3).
Traditional Supply and Delivery Resources
The 2010 optimization model includes flexibilty for a total of 100 distinct supply resources, the same
number utilzed in the 2008 modeL. The supply resources include long-term and spot gas supplies,
various on and off-system storage options, on system non-traditional supply resources (e.g. satellte LNG
alternative fuels) and DSM inputs. The inputs continue to include third-party interstate "citygate" deliveries
and other winter-only supply, As compared to the 2008 filng, this IRP continues to show that
Intermountain's peak and winter loads are growing faster than the average daily usage when compared to
current winter delivery options; however current peak and winter resources are adequate through FY15.
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The resource optimization model allows the user to input up to 30 Interstate transport resources. The
2010 model was adapted to include the capacity requirements and constraints associated with the new
"State Street" area.
The 2008 IRP indicated that the demand for winter and/or peak resources was growing rapidly. The
Company actively monitored the market for capacity and storage opportunities and was able to add new
liquid storage capacity to its contracted portolio. With this new storage capacity, the current models
indicate that the current levels of capacity and storage satisfy the Company's needs through 2015 even
under Design weather and high growth conditions.
89
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Non-Traditional Supply Resources
The 2010 IRP continued to utilze the expanded research and definitions of non-traditional resources that
was introduced in the 2008 IRP. The options included in the 2010 and 2008 filng include the same
researched resources as the 2006 section and also include wood chips, renewable biofuel production,
pipeline looping, remote or satellte LNG, and pipeline uprating. The newly included pipeline looping and
pipeline uprating, along with additional compressor station research, fall into the recently created sub-
section named "Capacity Upgrades"; which is now included in the Non-Traditional Supply Resources
section.
Distribution System
Intermountain used the same softare utilzed in 2008 to model the pressure and capacity of the
individual distribution systems. This softare has the capabilty to accurately represent a gas pipeline
system by applying user inputs such as customer loads, pressures, dimensions, etc. The results of these
engineering models are then used to determine the effectiveness and efficiency of potential system
capacity enhancements for each defined restraint point. As before, the model continues to project the
capacities for any projected scenario on the State Street Lateral, Idaho Falls Lateral, Sun Valley Lateral
and Canyon County area; which are then utilzed in the five-year growth projections.
The Efficient Use of Natural Gas
Intermountain continues to support and promote the need for efficient use of natural gas, and has
continued its conservation education efforts on behalf of its residential, commercial and industrial
customers.
Intermountain has 1) continued its annual mailng of brochures to all Core-market customers outlining
conservation tips and low income assistance, 2) maintained on its website information on residential and
commercial conservation measures, and maintained the abilty for customers to view their historical therm
usage anytime on-line, 3) maintained prominently on its website detailed conservation videos, 4) held
public meetings in conjunction with the IRP Planning Process meetings that emphasize conservation, 5)
continued to deploy and improve and industrial-customer website designed to provide real-time and
historical consumption data to better enable those customers to make wise energy management
decisions, and 6) continues to partner with various agencies on conservation information outreach,
Intermountain Gas Demand-Side Management Process
IGC continued its evaluation of natural gas efficiency and conservation opportunities. Similar to the
approach used in the 20081RP, the company's process focused on 1) ascertaining the level of achievable
and economically viable DSM that could provide a reliable resource in IGC's peak-load management, and
2) resources that facilitate year-round improvements in natural gas usage.
DSM Objectives
The company's DSM objectives remain unchanged from the 2008 IRP. The company's objectives
continue to be the following:
. Provide customer service
· Accommodate high efficiency and off-peak load growth
· Limit the need for new staffng resources
· Maintain competitive position as low-cost energy provider
. Provide environmental benefits
· Focus solely on the most cost-effective DSM measures
90
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
Assessment of Potential DSM Programs
r71"
, -1
For the 2010 Plan, similar to the 2008 IRP, the company continued to utilze information from the
Navigant Study to develop potential DSM programs. The Company's proposed programs continue to
focus on the residential market. In the New Construction market, similar to the 2008 IRP, the company
proposes to continue its promotion of high-effciency new construction in our advertising, builder
association participation, and through our ENERGY STAR Utilty Partner activities. The company stil
believes that this market-based approach makes the most sense in the new-construction arena.
In the Conversion market, the company evaluated the continuation of its $200 rebate program for
customers who at the time of conversion install a 90% or greater efficient natural gas furnace. The
company also evaluated expanding this program to existing customers that replace a lower efficiency
model with a 90%+ modeL. The company also evaluated providing a rebate to customers upgrading their
water heating equipment form .59 or below Energy Factor (EF) to a.64 or greater EF natural gas water
heater.
D"
~:, :,:,
i'.:L
(:1
rJ
Since completion of the 2008 IRP, the Company met with Staff to explore the creation of low-income
weatherization programs for residences heated with natural gas. The company held meetings with Staff
in 2009, and both Staff and the Company agreed that due to the abundance of Federal Stimulus Funds
for low-income weatherization, it made sense to delay further development and implementation of a low-
income targeted program. Key elements of any new program wil be to ensure that it is 1) cost-effective
on both a Total Resource Cost and Utility Cost, 2) additional low-income funds should be targeted
thereby maximizing the benefit of those incremental dollars. The Idaho Weatherization Network has
received $30 milion of Stimulus funding to weatherize low income homes in Idaho. These funds must be
spent by the end of March 2012. Therefore the company wil look hold meetings in late 2010, early 2011
to move forward with program design and development with the hope of including such a program with
the Company's 2011 PGA
Resource Optimization
J
U
Intermountain utilzed the same consultant and software vendor to run the 2010 optimization as was used
for the 2008 IRP. The 2010 model was enhanced over the prior program to include the new State Street
constraint area. The enhanced model continues to provide more than adequate capability to input supply,
storage, capacity and DSM resources.
...
:O
1
The results of the optimization runs indicate that the Company's current resource portolio of interstate
transport and storage capacity along with its term and spot gas supplies, are adequate to meet the
natural gas demands of southern Idaho, It does suggest that the increased reliance on spot or index
supplies in the winter could be replaced with an additional layer of term supply contracts while peaking
storage is adequate. Interstate capacity is suffcient although the model did select a small amount of
additional winter "Fil" capacity even when liquid storage was stil available indicative of delivered supply's
price advantage over liquid storage.
On-system load growth required the selection of available distribution system enhancements (e.g. various
pipe expansions and compression upgrades) in concert with minor use of some non-traditional resources
to meet all Design loads beginning in 2010.
The model selected the DSM resource, reflecting the proposed IF lateral pilot project, for each year
through 2015. Because each year's additional DSM savings is cumulative, each subsequent year's total
therm savings is higher than the preceding year, These results are similar to the 2008 IRP. The Company
wil continue to evaluate the effectiveness of additional DSM programs.
j
The final Optimization model run resulted in an overall system that met all forecasted design firm loads
and eliminated capacity deficits over the 5-year horizon. Thus the Company's portolio of supply, storage,
and capacity resources is sufficient through 2015 to meet the firm requirements of Intermountain's
customers even under Design weather conditions,
91
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
ATTACHMENT NO.1
Table 1.1
I 2010 IRP Design Base Case Industrial Forecst by Market Segment(Thousands of Therms)
2011 2012 2013
Potato Processors 91,983 92,038 92,148
Other Food Processors 64,850 68,031 68,340
Chemical & Fertilzer 30,440 30,440 30,440
Manufacturers 18,117 18,267 18,417
Institutions 14,584 14,840 15,064
Other 24,064 24,374 24,456
Total Base Case Forecast Therm Sales
244,036 247,990 248,865
,Table 1.2
I 2008 IRP Design Base Case Industrial Forecast by Market Segment(Thousands of Therms)
2011 2012 2013
Potato Processors 85,278 85,403 85,539
Other Food Processors 56,161 56,174 56,184
Chemical & Fertilzer 27,600 27,600 27,600
Manufacturers 24,323 24,357 24,400
Institutions 14,668 14,882 14,946
Other 16,763 16,612 16,771
Total Base Case Forecast Therm Sales
224,793 225,028 225,440
Table 1.3
2010 IRP Design Base Case Industrial Forecast by Market Segment
Over/(Under) the 2008 IRP Design Base Case
(Thousands of Therms)
2011 2012 2013
Potato Processors 6,705 6,635 6,609
Other Food Processors 8,689 11,857 12,156
Chemical & Fertilzer 2,840 2,840 2,840
Manufacturers (6,206)(6,090)(5,983)
Institutions (84)(42)(118)
Other 7,301 7,762 7,685
Total Base Case Forecast Therm Sales
19,243 22,962 23,425
92
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
ATTACHMENT NO.1
Total Company Design Weather/Base Growth 2010 IRP VS. 2008 IRP Usage Comparison
Table 2.1
':1
~l
2010 IRP LOAD DURATION CURVE - TOTAL COMPANY USAGE DESIGN BASE CASE
(Volumes in Therms)
NWP Firm Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD1 I2
2011 2,751,270 3,599,903 190,010 3,789,913
2012 2,743,760 3,652,007 190,010 3,842,017
2013 2,736,250 3,718,077 190,010 3,908,087
\'....,.1'.,.
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~......l..,',"
lFuture growth in transport CD is limited to T -4, which doe not affec Intermountain's interstate pipeline capacity requirements.
Table 2.2
2008 IRP LOAD DURATION CURVE - TOTAL COMPANY USAGE DESIGN BASE CASE
(Volumes in Therms)
'1'
t:"¡ ,t..
'Jì.
J
NWPFirm Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD1 Total
2011 2,751,270 3,837,766 190,630 4,028,396
2012 2,743,760 3,949,245 190,630 4,139,875
2013 2,736,250 4,060,829 190,630 4,251,459
lFuture growt in transport CD is limited to T -4, which does not affect Intermountain's interstate pipeline capacity requirements.
Table 2.3
d
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it.
~J
J
¡~- ,j
2010 IRP LOAD DURATION CURVE - TOTAL COMPANY DESIGN BASE CASE
Over/-Under 2008 IRP
(Volumes in Therms)
NWP
Firm Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD1 Total
2011 0 237,863 -620 238,483
2012 0 297,238 -620 297,858
2013 0 342,752 -620 343,372
lFuture growth in transport CD is limited to T-4, which does not affect Intermountain's interstate pipeline capacity requirements.
93
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
ATTACHMENT NO.1
Total Company Peak Day Deliverabilty Comparison for 2010 IRP vs. 2008 IRP
Table 3.1
2010 IRP PEAK DAY FIRM DELIVERY CAPABILITY
(Volumes in Therms)
2011
Maximum Daily Storage Withdrawals:
Nampa LNG
Plymouth LS
Jackson Prairie SGS
Total Storage
Maximum Deliverabilty (NWP)
Total Peak Day Deliverabilty
600,00
1,132,00
303.370
2,035,370
2,751,270
4.786.640
2012
600,000
1,132,000
303.370
2,035,370
2,743,760
4779130
2013
600,000
1,132,000
303,370
2,035,370
2,736.250
4771620
Table 3.2
2008 IRP PEAK DAY FIRM DELIVERY CAPABILITY
(Volumes in Therms)
2011
Maximum Daily Storage Withdrawals:
Nampa LNG
Plymouth LS
Jackson Prairie SGS
Total Storage
Maximum Deliverabilty (NWP)
Total Peak Day Deliverabilty
600,000
1,132,000
303.370
2,035,370
2,751.270
4.786640
2012
600,000
1,132,000
303,370
2,035,370
2,743,760
4779130
~
600,000
1,132,000
303.370
2,035,370
2,736.250
4.771.620
Table 3.3
2010 IRP PEAK DAY FIRM DELIVERY CAPABILITY
Over/(Under) 2008 IRP
(Volumes in Therms)
2011 2012 2013
Maximum Daily Storage Withdrawals:
Nampa LNG 0 0 0
Plymouth LS 0 0 0
Jackson Prairie SGS Q Q Q
Total Storage 0 0 0
Maximum Deliverabilty (NWP)Q Q Q
Total Peak Day Deliverabilty Q Q Q
94
I
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
'1'\'.c.
ATTACHMENT NO.1
Total Company Peak Delivery Deficit for 2010 IRP VS. 2008 IRP
Table 4.1
~l
2010 IRP FIRM DELIVERY DEFICIT - TOTAL COMPANY DESIGN BASE CASE
"1'
."::Peak Day Deficit'
Total Winter Deficif
Days Requiring Additional Resources
(Volumes in Therms)~
o
o
o
2012
o
o
o
~
o
o
o
lPeaking storage Increases by 78,370 thenns per day in 2010.
2Equal to the total winter sendout in excess of interste capacity less total 'peaking' storage. Peaking storage does not
require the use of Intennountain's traditional interstate capacity to deliver inventory to the citgate."J
"'"::
t...
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i:..
i:.;
Table 4.2
'1
d
Peak Day Deficit'
Total Winter Deficit
Days Requiring Additional Resources
2008 IRP FIRM DELIVERY DEFICIT - TOTAL COMPANY DESIGN BASE CASE
(Volumes in Therms)
2011
o
o
o
~
o
o
o
2013
o
o
o
( J
........,1 Peaking storage increases by 78,370 thenns per day in 2010.
2Equal to the total winter sendout in excess of intersate capacity less total 'peaking' storage. Peaking storage dos not
require the use of Intennountain's traditional interstate capacity to deliver inventory to the citygate.f .1
".i,
Table 4.3
iJ
J Peak Day Deficit'
Total Winter Deficit
Days Requiring Additional Resources
20081RP FIRM DELIVERY DEFICIT - TOTAL COMPANY DESIGN BASE CASE
(Volumes in Therms)
2011
o
o
o
2012
o
o
o
2013
o
o
o
, 1.
iJ
'Peaking storage increased by 78,370 thenns per day in 2008.
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.
,J
95
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
ATTACHMENT NO.1
Idaho Falls Lateral Design Weather/Base Growth Comparison for 2010 IRP VS. 2008 IRP
Table 5.1
2010 LOAD DURATION CURVE -IDAHO FALLS DESIGN BASE CASE
(Volumes in Therms)
Existing
Distribution Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD1 Total
2011 810,000 657,874 221,750 879,624
2012 810,000 668,933 221,750 890,683
2013 810,000 685,566 221,750 907,316
1 Existing firm contract dem includes T.5 and T -4 requiremen.
Table 5.2
2008 LOAD DURATION CURVE - IDAHO FALLS DESIGN BASE CASE
(Volumes in Therms)
Existing
Distribution Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD1 Total
2011 810,000 707,330 221,750 875,000
2012 810,000 732,419 221,750 903,050
2013 810,000 757,149 221,750 929,105
lExisting firm contract demand includes T.5 and T-4 requirements.
Table 5.3
2010 LOAD DURATION CURVE -IDAHO FALLS DESIGN BASE CASE
Over/(Under) 2008 IRP
(Volumes in Therms)
Existing
Distribution Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD1 Total
2011 0 (49,456)0 (49,456)
2012 0 (63,486)0 (63,486)
2013 0 (71,583)0 (71,583)
1 Existing firm contract demand includes T.5 and T -4 requirements.
96
'-1
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
ATTACHMENT NO.1
Idaho Falls Lateral Delivery Deficit Comparison for 2010 IRP vs. 2008 IRP
Table 6.1
2010 IRP FIRM DELIVERY DEFICIT -IDAHO FALLS DESIGN BASE CASE
(Volumes in Therms)
'-'1
I
W1 2012 2013
J
C,_,-)
~..'
~::~'C.~
Peak Day Deficit 1
Total Winter Deficir
69,620 80,680 97,320
93,090 123,350 178,490
Days Requiring Additional Capacity 2 3 3
lEqual to the total winter sendout in excess of distribution capacity.
Table 6.2
2008 IRP FIRM DELIVERY DEFICIT - IDAHO FALLS DESIGN BASE CASE
(Volumes in Therms)
!'1'
i.L
" J, '
;- J
2011 2012 2013
Peak Day Deficit 1 119,080 144,170 168,900
Total Winter Deficir 263,220 369,340 481,140
Days Requiring Additional Capacity 4 5 5
lEqual to the total winter sendout in excess of distribution capacity.
Table 6.3
2010 IRP FIRM DELIVERY DEFICIT -IDAHO FALLS DESIGN BASE CASE
Over/(Under) 2008 IRP
(Volumes in Therms)
J
i:;.:~)
2011 2012 2013
Peak Day Deficit 1 (49,460)(63,490)(71,580)
Total Winter Deficir (170,130)(245,990)(302,650)
Days Requiring Additional Capacity (2)(2)(2)
IE ual to the total winter sendout in excess of distribution ca aci
97
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
ATTACHMENT NO.1
Sun Valley Lateral Design Weather/Base Growth Comparison for 2010 IRP VS. 20081RP
Table 7.1
2010 IRP LOAD DURATION CURVE - SUN VALLEY DESIGN BASE CASE
(Volumes in Therms)
Existing
Distribution Peak Day Send out
Transport Core Industrial
Capacity Market Firm CD1 I2
2011 175,000 173,957 8,150 182,107
2012 175,000 176,272 8,150 184,422
2013 175,000 176,554 8,150 184,704
1Existing finn contract demand includes T-1, T-2, and T -4 requirement.
Table 7.2
20081RP LOAD DURATION CURVE - SUN VALLEY DESIGN BASE CASE
(Volumes in Therms)
Existing
Distribution Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD1 Total
2011 180,000 180,230 8,150 188,380
2012 180,000 184,037 8,150 192,187
2013 180,000 187,705 8,150 195,855
1 Existing finn contract demand includes T -1, T -2, and T -4 requirement.
Table 7.3
2010 IRP LOAD DURATION CURVE - SUN VALLEY DESIGN BASE CASE
Over/(Under) 20081RP
(Volumes in Therms)
Existing
Distribution Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD1 Total
2011 (50,000)(6,273)0 (6,273)
2012 (50,000)(7,765)0 (7,765)
2013 (50,000)(11,151)0 (11,151)
1Existing finn contract demand includes T-1, T-2, and T-4 requirements.
98
ri
('I
'1
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
ATTACHMENT NO.1
Sun Valley Lateral Delivery Deficit Comparison for 2010 IRP vs. 2008 IRP
Table 8.1
2010 IRP FIRM DELIVERY DEFICIT - SUN VALLEY DESIGN BASE CASE
(Volumes in Therms)
n
L:j
1"')
1.-,:::,,~'
2011 ~2013
Peak Day Deficit 1 7,110 9,420 9,700
Total Winter Deficif 9,710 17,470 17,790
Days Requiring Additional Capacity 2 2 3
lEqual to the tota winter sendout in excess of distribution capacit.
Table 8.2
2008 IRP FIRM DELIVERY DEFICIT - SUN VALLEY DESIGN BASE CASE
(Volumes in Therms)il ~~
Peak Day Deficit 1 8,380 12,190 15,860
1
,J
, 1
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· ..J.'.'.
Total Winter Deficit 13,960 25,130 38,500
Days Requiring Additional Capacity 2 3 4
lEquai to the total winter sendout in excess of distribution capacity.
Table 8.3
2010 IRP FIRM DELIVERY DEFICIT - SUN VALLEY DESIGN BASE CASE
Over/(Under) 2008 IRP
(Volumes in Therms)
.J
2011 2012 2013
Peak Day Deficit 1 (1,270)(2,770)(6,160)
Total Winter Deficit (4,250)(7,660)(20,710)
Days Requiring Additional Capacity 0 (1 )(1 )
lEqual to the total winter sendout in excess of distribution capacity.
I,~d
99
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
ATTACHMENT NO.1
Canyon County Area Design WeatherlBase Growth Comparison for 2010 IRP VS. 2008 IRP
Table 9.1
2010 LOAD DURATION CURVE - CANYON COUNTY DESIGN BASE CASE
(Volumes in Therms)
Existing
Distribution Peak Day Sendout
Transport Core Industrial
Capacity Market Firm cot Total
2011 690,000 514,n6 100,100 614,876
2012 690,000 530,6n 100,100 630,n7
2013 690,000 544,680 100,100 644,780
1 Existing finn contra demand includes T -1, T -2, and T -4 requirements.
Table 9.2
2008 LOAD DURATION CURVE -CANYON COUNTY DESIGN BASE CASE
(Volumes in Therms)
Existing
Distribution Peak Day Sendout
Transport Core Industrial
Capacity Market Firm cot Total
2011 690,000 567,020 102,500 669,520
2012 690,000 591,117 102,500 693,617
2013 690,000 614,610 102,500 717,110
1 Existing finn contract demand includes T -1, T -2, and T -4 requirements.
Table 9.3
2010 LOAD DURATION CURVE - CANYON COUNTY DESIGN BASE CASE
Over/(Under) 2008 IRP
(Volumes in Therms)
Existing
Distribution Peak Day Sendout
Transport Core Industrial
Capacity Market Firm cot Total
2011 0 (52,244)(2,400)(54,644)
2012 0 (60,440)(2,400)(62,840)
2013 0 (69,930)(2,400)(72,330)
1 Existing finn contract demand includes T -1, T -2, and T -4 requirements.
100
"1'~: :'
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
ATTACHMENT NO.1
Canyon County Area Firm Delivery Deficit Comparison for 2010 IRP vs. 2008 IRP
Table 10.1
2010 IRP FIRM DELIVERY DEFICIT - CANYON COUNTY DESIGN BASE CASE
(Volumes in Therms)
2011 2012 2!
Peak Day Deficit'o o o
Total Winter Deficir o o o
Fl..
t:::L
Days Requiring Additional Capacity o o o
'Equal to the total winter sendout in excess of distributon capacity.
~i
Table 10.2
2008 IRP FIRM DELIVERY DEFICIT - CANYON COUNTY DESIGN BASE CASE
(Volumes in Therms)
q
tJ
fJ'
(_.~
:1
. ~ :
'.'-~
2011 2012 2013
Peak Day Deficit'0 362 2,711
Total Winter Deficir 0 362 3,473
Days Requiring Additional Capacity 0 1 2
'Equal to the total winter sendout in excess of distribution capacity.
Table 10.3
LJ 2010 IRP FIRM DELIVERY DEFICIT - CANYON COUNTY DESIGN BASE CASE
Over/(Under) 2008 IRP
(Volumes in Therms)
(" 'J
L"
J
,J
2011 2012 2013
Peak Day Deficit'0 (362)(2,711 )
Total Winter Deficir 0 (362)(3,473)
Days Requiring Additional Capacity 0 (1 )(2)
'Equal to the total winter sendout in excess of distribution capacity,
101
Intermountain Gas Company
2011 - 2015 Integrated Resource Plan
ATTACHMENT NO.1
Total Company Firm Receipt Point Capacity comparison for 2010 IRP VS. 20081RP
Table 11.1
Intermountain Gas Company
2010 IRP Firm Receipt Point Capacity Through 2013
Volumes in Dth
Receipt Point 2011 ~2013
"
Sumas 41,146 41,146 41,146
Stanfield 115,429 115,429 115,429
Rockies 92,552 91,801 91,050
Storage 203,537 203,537 203,537
Citygate 26,000 26,000 26,000
Total 478,664 477,913 477,162
Table 11.2
Intermountain Gas Company
2008 IRP Firm Receipt Point Capacit Through 2013
Volumes in Dth
Receipt Point 2011 2012 2013
Sumas 41,146 41,146 41,146
Stanfield 115,429 115,429 115,429
Rockies 92,552 91,801 91,050
Storage 203,537 203,537 203,537
Citygate 25,000 25,000 26,000
"otal 478,664 477,913 477,162
Table 11.3
Intermountain Gas Company
2010 IRP Firm Receipt Point Capacity Through 2013
Overl (Under) 2008 IRP
Volumes in Dth
Receipt Point 2011 2012 2013
Sumas 0 0 0
Stanfield 0 0 0
Rockies 0 0 0
Storage 0 0 0
Citygate 0 0 0
Total 0 0 0
102