20130228Integrated Resource Plan.pdf

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EXECUTIVE OFFICES
INTERMOUNTAIN GAS COMPANY
555 SOUTH COLE ROAD • P.O. BOX 7608 • BOISE, IDAHO 83707 • [phone] • FAX: [phone]
February 28, 2013
Ms. Jean Jewell
Idaho Public Utilities Commission
472 W. Washington Street
P.O. Box 83720
Boise, ID 83720-0074
RE: Intermountain Gas Company's 2013 Integrated Resource Plan
Case No. INT-G-13-03
Dear Ms. Jewell:
Enclosed for filing with this Commission are the original and seven (7) copies of Intermountain
Gas Company's 2013 Integrated Resource Plan.
If you have any questions or require additional information regarding the attached, please contact
me at 377-6105 or Dave Swenson at 377-6118.
Very truly yours,
it
Scott W. Madison
EVP and General Manager
cc: M. Parvinen
D. Haider
B. Morman
Intermountain Gas Company
2013-2017 Integrated Resource Plan
Table of Contents
EXECUTIVESUMMARY ................................................................................................................................. 5
DEMANDFORECAST OVERVIEW .............................................................................................................. 14
CUSTOMER GROWTH FORECAST ............................................................................................................15
HEATING DEGREE DAYS AND DESIGN WEATHER .................................................................................27
USAGEPER CUSTOMER ............................................................................................................................ 31
INDUSTRIALFORECAST .............................................................................................................................37
LOADDEMAND CURVES ............................................................................................................................ 42
TRADITIONAL SUPPLY-SIDE RESOURCES 49
NON-TRADITIONAL SUPPLY RESOURCES .............................................................................................. 60
DISTRIBUTION SYSTEM MODELING .........................................................................................................63
AVAILABLE AND POTENTIAL SYSTEM CAPACITY ENHANCEMENTS .................................................65
THE EFFICIENT AND DIRECT USE OF NATURAL GAS ...........................................................................67
DEMAND-SIDE MANAGEMENT ..................................................................................................................74
RESOURCEOPTIMIZATION ........................................................................................................................ 76
COMPARATIVE ANALYSIS 2012 IRP VS. 2010 IRP ..................................................................................84
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Intermountain Gas Company
2013— 2017 Integrated Resource Plan
Table of Exhibits
Exhibit No. I
Appendix A:
Appendix B:
Appendix C:
Appendix D:
Appendix E:
Appendix F:
Exhibit No. 2
Appendix A:
Appendix B:
Exhibit No. 3
Appendix A:
Appendix B:
Appendix C:
Appendix D:
Appendix E:
Exhibit No. 4
Maps 1 —3
Charts 1-6
Table 1:
Table 2:
Table 3:
Table 4:
Table 5.1:
Table 5.2:
Table 5.3:
Table 5.4:
Table 5.5:
John Church Economic Forecast
Intermountain Gas Market Penetration rates
Intermountain Gas Market Conversion Rates
Base Case - New Customers, Adjustments & Total Customer
Forecast
High Case - New Customers, Adjustments & Total Customer
Forecast
Low Case - New Customers, Adjustments & Total Customer
Forecast
Regression Statistical Output
Regression Data
Total Company: Design Weather - Base Price/Base Growth LDC
Idaho Falls Lateral: Design Weather - Base Price/Growth LDC Data
Canyon County Area: Design Weather - Base Price/Growth LDC
Data
Sun Valley Lateral: Design Weather - Base Price/Growth LDC Data
State Street Lateral: Design Weather - Base Price/Growth LDC Data
Load Duration Curve Inputs
Supply Resource Inputs
Transport Capacity Inputs
Supply Resource Pricing Inputs
2013 Optimization Model Results
2014 Optimization Model Results
2015 Optimization Model Results
2016 Optimization Model Results
2017 Optimization Model Results
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Intermountain Gas Company
2013-2017 Integrated Resource Plan
Exhibit No. 5
Appendix A: Boise/Idaho Falls Public Workshop Announcement & Agenda
Appendix B: Workshop Presentation
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Intermountain Gas Company
2013 - 2017 Integrated Resource Plan
EXECUTIVE SUMMARY
Natural gas continues to be the fuel of choice in Idaho. Southern Idaho's manufacturing plants,
commercial businesses, new homes and 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"I'IGC") endorses and encourages the wise and efficient use of energy in
general and, in particular, natural gas for high efficient uses in Intermountain's service area (see Page
67).
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. This
Integrated Resource Plan ("IRP") represents a snapshot in time of Intermountain's ongoing planning
process. It is not meant to be a prescription for all future energy resource decisions, as conditions will
change over the planning horizon covered by this IRP. Rather, this document is meant to describe the
currently anticipated conditions for 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.
Public input is an essential part of the IRP planning process. Intermountain held Public Meetings in Boise
and Idaho Falls to present the supply and demand planning process to its customers and stakeholders.
The participants were encouraged to provide feedback to Intermountain on its process and assumptions.
That feedback was analyzed and incorporated into this final plan.
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. Intermountain serves over 315,000 customers in 74 communities through a system of over
11,000 miles of transmission, distribution and service lines. Over 16 miles of transmission, 34 miles of
distribution and 66 miles of service lines were added during 2012 to accommodate new customer
additions and maintain service for Intermountain's growing customer base.
The economy of Intermountain's service area is based primarily on agriculture and related industries. The
major crops produced in Southern Idaho are potatoes and sugar beets. Key agricultural-related industries
include food processing and production of chemical fertilizers. Other significant industries are electronics,
general manufacturing and services and tourism.
Intermountain provides natural gas sales and service to two major markets: the residential/commercial
market (or core market) and the industrial market. During 2012, an average of 285,275 residential and
30,428 commercial customers used natural gas primarily for space and water heating, compared to an
average of 282,309 residential and 30,139 commercial customers in 2011. This equates to an increase in
average residential and commercial customers of 1.0%.
Intermountain's industrial customers transport natural gas through lntermountain'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. Industrial sales and transportation accounted for
49.8% of the throughput on Intermountain's system during 2012.
Intermountain's peak day loads (throughput during the projected coldest winter day) are growing at a
slower rate than was forecast in the 2010 IRP. 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 2010 and 2012 IRP's.
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Intermountain Gas Company
2013-2017 Integrated Resource Plan
However, this IRP does show peak day load growth, albeit at a slower rate, over the planning period.
This 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.
The customer growth forecast' was created and analyzed from a total company perspective and also by
specific distribution system segments. These distribution system segments are distinct geographic
regions within Intermountain's service territory. The regions were selected based upon the anticipated or
known need for system upgrades within these certain regions. The Segments, as more fully delineated
later in this document, consist of The Idaho Falls Lateral, The Sun Valley Lateral, The Canyon County
Area, the State Street Lateral and the All Other Segment.
Peak day sendout studies and load demand curves were developed under design weather conditions to
determine the magnitude and timing of future deficiencies in firm peak day delivery capabilities from both
a total company interstate mainline perspective, as well as geographic region specific perspectives.
Residential, commercial and industrial customer peak day sendout was matched against available
resources to determine which combination of new resources would be needed to meet Intermountain's
future peak day delivery requirements in the most cost effective manner.
FORECAST PEAK DAY SENDOUT
Total Company
Residential, commercial and industrial peak day load growth on lntermountain's system under design
conditions is forecast over the five-year period to grow at an average annual rate of 1.03% under the
base case scenario. The table below summarizes the forecast for peak day sendout under the "base
case" customer growth assumption.
LOAD DEMAND CURVE - TOTAL COMPANY DESIGN BASE CASE
(Volumes in Therms)
NWP Firm Peak Day Sendout Incremental Peak Day Sendout
Transport Core Industrial Core Industrial
Capacity Market Firm CD Total Market Firm CD1 Total
2013 2,781,100 3,577,100 146,113 3,723,211
2014 2,751,950 3,622,450 146,113 3,768,562 45,350 0 45,350
2015 2,651,950 3,671,920 146,113 3,818,036 49,470 0 49,470
2016 2,571,390 3,720,820 146,113 3,866,195 48,900 0 48,900
2017 2,571,390 3,769,680 146,113 3,915,793 48,860 0 48,860
'Future growth in transport CD is limited to T-4, which does not affect Intermountain's interstate pipeline capacity requirements.
The above table highlights the fact that growth in the peak day is driven by the growth projected to occur
in Intermountain's residential and small commercial customer markets.
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
Page 15)
Intermountain Gas Company
2013-2017 Integrated Resource Plan
Existing Resources
Intermountain's existing firm delivery capability on the peak day is made up of the resources shown in the
following table:
PEAK DAY FIRM DELIVERY CAPABILITY
(Volumes in Therms)
2013 2014 2015 2016 2017
Maximum Daily Storage Withdrawals:
Nampa LNG 600,000 600,000 600,000 600,000 600,000
Plymouth LS 1,132,000 1,132,000 1,132,000 1,132,000 1,132,000
Jackson Prairie SGS 303.370 303.370 303.370 303,370 303.370
Total Storage 2,035,370 2,035,370 2,035,370 2,035,370 2,035,370
Maximum Deliverability (NWP) 2.736.250 2,728.740 2,699,590 2.509.590 2,429.030
Total Peak Day Deliverability 4.468.250 4.460.740 4.431.590 4.241.590 4.161.030
When forecasted peak day sendout is matched against existing resources, there are no peak day delivery
deficits during the IRP planning period (see "Load Demand Curves" Page 42).
FIRM DELIVERY DEFICIT - TOTAL COMPANY DESIGN BASE CASE
(Volumes in Therms)
2013 2014 2015 2016 2017
Peak Day Deficit 0 0 0 0 0
Total Winter Deficit 0 0 0 0 0
Days Requiring Additional Resources 0 0 0 0 0
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.
Similar to 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
and T-5 customers) were also included as part of these regional studies. A wide array of alternatives
were evaluated in formulating the best plan to meet any projected deficits in the various regions within
Intermountain's service territory (see "Non-Traditional Supply Resources" Page 60). Additionally, each
region is analyzed within the framework of the Company's Distribution System Model (See Page 63).
Idaho Falls Lateral Region
The Idaho Falls Lateral ("IFL") is 104 miles in length and serves a number of cities between Pocatello in
the south 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 17% of the total company
customers in the 2012 base year of the IRP forecast.
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Intermountain Gas Company
2013 - 2017 Integrated Resource Plan
The 2010 IRP identified the potential for peak day deficits on the IFL. To meet the projected growth
requirements, IGC completed a 16" pipeline loop around the city of Idaho Falls. With the completion of
this Phase V Project in the winter of 2012, the distribution system capacity on the IFL increased to
990,000 therms from 810,000. This increase is enough to ensure no potential peak day deficits through
the IRP planning horizon.
LOAD DEMAND CURVE - IDAHO FALLS DESIGN BASE CASE
(Volumes in Therms)
Existing
Distribution Peak Day Sendout Incremental Peak Day Sendout
Transport Core Industrial Core Industrial
Capacity Market Firm CD' Total Market Firm CD2 LQ1
2013 990,000 651,550 239,550 891,100
2014 990,000 661,450 239,550 901,000 9,900 0 9,900
2015 990,000 672,120 239,550 911,670 10,670 0 10,670
2016 990,000 682,270 239,550 921,820 10,150 0 10,150
2017 990,000 692,410 239,550 931,960 10,140 0 10,140
'Existing firm contract demand includes T-1, T-2 and T4 requirements.
2Future growth in transport CD is limited to T4 which only impacts Intennountain's distribution capacity requirements.
FIRM DELIVERY DEFICIT - IDAHO FALLS DESIGN BASE CASE
(Volumes in Therms)

2013 2014 2015 2016 2017
Peak Day Deficit' 0 0 0 0 0
Total Winter Deficit 2 0 0 0 0 0
Days Requiring Additional Capacity 0 0 0 0 0
'Equal 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 traditional interstate capacity to deliver inventory to the citygate.
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Intermountain Gas Company
2013-2017 Integrated Resource Plan
Sun Valley Lateral Region
The residential, commercial and industrial load served by the Sun Valley Lateral ("SVL") represents
approximately 4% of the total company customers in the base year of the IRP forecast.
The 2010 IRP revealed potential peak day deficits on the SVL beginning as soon as 2011. To ensure
adequate capacity on the lateral, Intermountain installed a compressor station during the winter of
2010/2011 to boost pressure on the SVL. The compressor station brought the SVL capacity to 204,000
therms from the previous level of 175,000. This increased capacity ensures no peak day delivery deficits
over the IRP planning horizon as illustrated in the following tables.
LOAD DEMAND 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 CD' Total Market Firm CD2 Total
2013 204,000 164,690 8,150 172,840
2014 204,000 165,840 8,150 173,990 1,150 0 1,150
2015 204,000 167,560 8,150 175,710 1,720 0 1,720
2016 204,000 169,320 8,150 177,470 1,760 0 1,760
2017 204,000 171,010 8,150 179,160 1,690 0 1,690
'Existing firm contract demand includes T-1, T-2 and T4 requirements.
2Future growth in transport CD is limited to T-4 which only impacts Intermountain's distribution capacity requirements.
FIRM DELIVERY DEFICIT - SUN VALLEY DESIGN BASE CASE
(Volumes in Therms)

2013 2014 2015 2016 2017
Peak Day Deficit' 0 0 0 0 0
Total Winter Deficit2 0 0 0 0 0
Days Requiring Additional Capacity 0 0 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
2EquaI 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.
Intermountain Gas Company
2013-2017 Integrated Resource Plan
Canyon County Region
The residential, commercial and industrial load served by the Canyon County Lateral ("CCU) represented
approximately 15% of the total company customers during the IRP base year.
When forecasted CCL peak day design sendout is matched against the existing peak day distribution
capacity (680,000 therms), there are no peak day delivery deficits that occur during the 2013-2017
planning years as shown in the following tables:
LOAD DEMAND CURVE - CANYON COUNTY DESIGN BASE CASE
(Volumes in Therms)
Existing
Distribution Peak Day Sendout Incremental Peak Day Sendout
Transport Core Industrial Core Industrial
Capacity Market Firm CD1 Total Market Firm CD2 Total
2013 680,000 509,640 93,310 602,950
2014 680,000 518,160 93,310 611,470 8,520 0 8,520
2015 680,000 527,580 93,310 620,890 9,420 0 9,420
2016 680,000 537,790 93,310 631,100 10,210 0 10,210
2017 680,000 548,840 93,310 642,150 11,050 0 11,050
'Existing firm contract demand includes T-1, 1-2 and T-4 requirements.
2Future growth in transport CD is limited to T-4 which only impacts Intermountain's distribution capacity requirements.
FIRM DELIVERY DEFICIT - CANYON COUNTY DESIGN BASE CASE
(Volumes in Therms)

2013 2014 2015 2016
Peak Day Deficit' 0 0 0 0 0
Total Winter Deficit 2 0 0 0 0 0
Days Requiring Additional Capacity 0 0 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
2EquaI 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.
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Intermountain Gas Company
2013-2017 Integrated Resource Plan
State Street Lateral
The residential, commercial and industrial load served by the State Street Lateral ("SSL") represented
approximately 14% of the total company customers during the base year of the IRP forecast.
Although there are currently no capacity constraints on the SSL it remains an area that Intermountain is
watching, and will continue to watch as demand begins to approach design capacity. During the 2013-
2017 time frame, there are no capacity constraints as shown in the following tables:
LOAD DEMAND CURVE - STATE STREET DESIGN BASE CASE
(Volumes in Therms)
Existing
Distribution Peak Day Sendout Incremental Peak Day Sendout
Transport Core Industrial Core Industrial
Capacity Market Firm CD' Total Market Firm CD2 Total
2013 585,000 500,620 16,000 516,620
2014 585,000 505,660 16,000 521,660 5,040 0 5,040
2015 585,000 510,730 16,000 526,730 5,070 0 5,070
2016 585,000 515,750 16,000 531,750 5,020 0 5,020
2017 585,000 520,800 16,000 536,800 5,050 0 5,050
Future growth in transport CD is limited to T-4 which only impacts lntem,ountain's distribution capacity requirements.
FIRM DELIVERY DEFICIT - STATE STREET DESIGN BASE CASE
(Volumes in Therms)

2013 2014 2015 2016 2017
Peak Day Deficit' 0 0 0 0 0
Total Winter Deficit 2 0 0 0 0 0
Days Requiring Additional Capacity 0 0 0 0 0
'Equal 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 traditional interstate capacity to deliver inventory to the citygate.
ASSESSMENT OF POTENTIAL DEMAND SIDE MANAGEMENT PROGRAMS
In addition to reviewing traditional and non-traditional resource alternatives, ICC has also analyzed
potential Demand Side Management ("DSM") measures as a solution for potential constraint areas.
Intermountain updated its Navigant DSM study to reflect current market conditions, efficiency
assumptions and natural gas costs. 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,
would provide truly additional energy savings, and would meet a Total Resource Cost test threshold (See
"Demand Side Management" Page 74).
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Intermountain Gas Company
2013-2017 Integrated Resource Plan
Since the 2010 IRP was completed, natural gas prices have continued to fall dramatically.
lntermountain's core market customers have seen a 40% price reduction since 2008. Because of this,
DSM programs that were previously considered for pilot programs no longer provide cost benefits in the
new price environment. Additionally, the U.S. Department of Energy has set new rules mandating higher,
region-based minimum efficiency standards for gas water heaters beginning in April 2015.
IGC continues to offer a $200 rebate for customers converting to natural gas if they purchase a 90%-or-
greater efficiency furnace. This program will remain in place. Intermountain's advertising promotion of
high-efficiency homes and ENERGY STAR to the new construction market 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 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 any potential deficits. In utilizing 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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Intermountain Gas Company
2013-2017 lnteQrated Resource Plan
DEMAND FORECAST OVERVIEW
The first step in resource planning is forecasting future load requirements. Three essential components
of the load forecast include projecting the number of customers requiring service, forecasting the weather
sensitive customers' response to temperatures and estimating the weather those customers may
experience. To complete the demand forecast, 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 profiles 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.
Intermountain's resource planning looks at distinct segments within its current distribution system. After
analyzing resource requirements at the segment level, the data is aggregated to provide a Total
Company perspective. The Segments for planning purposes are as follows:
The Canyon County Segment, which consists of the core market customers in Canyon County.
• The Sun Valley Lateral Segment, consisting of the core market customers in Blame and Lincoln
Counties.
• The Idaho Falls Lateral Segment, consisting of the core market customers in Bingham,
Bonneville, Fremont, Jefferson, and Madison Counties, along with approximately 35% of the core
market customers in Pocatello, Bannock County.
• The State Street Lateral Segment 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 was newly-defined in the 2010 IRP.
• The All Other Customers Segment, consisting of the core market customers in Ada County not
included in the SSL 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.
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Intermountain Gas Company
2013-2017 Integrated Resource Plan
CUSTOMER GROWTH FORECAST
Customer growth is the driving factor in IGC's five-year demand forecast contained within the IRP. The
customer growth forecast provides the anticipated magnitude and direction of Intermountain's residential
and small commercial growth by IGC Distribution System Segment. Intermountain's customer growth
forecast includes three (3) key components, residential new construction customers, residential
customers who convert to natural gas from an alternative fuel, and small commercial customers
RESIDENTIAL NEW CONSTRUCTION CUSTOMERS
To calculate the number of customers added each year, the annual change in households for each
county in the IGC Service Territory is determined using the Idaho Economics 2011 Economic Forecast for
the State of Idaho by John S. Church ('11 Forecast), dated June 2011 (see Exhibit No. 1, Appendix A).
Using the assumption that a new household means a new dwelling is needed, the annual change in
households by county is multiplied by IGC's market penetration rate in that region to determine the
additional residential new construction customers. Next, that number is multiplied by the IGC conversion
rate, which is the anticipated percentage of conversion customers relative to new construction customers
in those locales. This results in the number of expected residential conversion customers, and when
added to the residential new construction numbers, the total expected additional residential customers
across the periods is derived, by county.
Although the 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 (TAZ) in the State Street segment was compared to the overall
forecast growth for all of Ada County. The forecast growth in the State Street segment was calculated to
be 27%. This rate was used as the basis 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 Intermountain'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.
With the continued downturn in the housing market, IGC growth projections are down considerably, when
compared to the 2010 IRP. The '11 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.
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Intermountain Gas Company
2013-2017 Integrated Resource Plan
The following graph depicts the relationship or "shape" of customer additions by segment:
The 11 Forecast contains three economic scenarios: base case, low growth, and high growth. IGC has
incorporated these scenarios into the customer growth model, and has developed three five-year core
market customer growth forecasts. The following graph shows the annual additional customers for each
of the three economic scenarios.
Annual Additional Customers
Residential and Small Commercial
I 7,000
-U-High Growth
-s-Base Case
-k-Low Growth
13 FY14 FY15 FY16 F'
5,000
3,000
1,000
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Intermountain Gas Company
2013-2017 Integrated Resource Plan
The following graph shows the difference in base case annual additional customers between the 2010
and 2012 IRP forecasts:
Annual Additional Customers
Residential and Small Commercial
2012 IRP vs. 2010 IRP
10,000
8,000
2010 IRP
6,000 -.-2012 IRP
4,000
2,000
FYI FY14 FY15
As indicated, the continued 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 2010 and 2012 IRP's.
The following table shows the results from the 5-year customer growth model for each scenario for the
total customers at each year-end, and the annual additional or incremental, customers:
TOTAL CUSTOMERS ANNUAL ADDITIONAL CUSTOMERS
Range as a % Average as a % Range as a % Average as a %
Of Base Case of Base Case Of Base Case of Base Case
Low Growth 97%-99% 98% 48%-52% 50%
Baseline 100%-100% 100% 100%-100% 100%
High Growth 101%-103% 102% 141%-147% 143%
Range Range
(2013 - 2017) Avera-ge (2013 - 2017) AveraQe
Low Growth 169525 -324,683 320,709 2,055-2,390 2,210
Baseline 18,512 -335,591 120,220
327,126 4,100-4,550 4,390
High Growth - 345,075 332,655 5,815- 6,485 6,288
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Intermountain Gas Company
2013-2017 Integrated Resource Plan
Household Projections! Church Forecast
The 11 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. It 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 '11 Forecast uses two methods for population projections: (1) a cohort-component population model
in which annual births and deaths are forecast, and then the net number is either added to or subtracted
from the population; and (2) an econometric model which forecasts population as a function of economic
activity. The two forecasts are then compared and reconciled for each quarter of the forecast. Migration
into or out of the state is arrived at in this reconciliation.
As previously mentioned, the '11 Forecast provides three scenarios: (1) baseline, (2) high growth, and (3)
low growth. The baseline scenario assumes a normal amount of economic fluctuation, or a normal
business cycle. This becomes the standard against which changes in customer growth, as affected by
the low and high growth scenarios can be measured.
The Base Case Economic Growth Scenarios
The '11 Forecast for the State of Idaho and its 44 counties forecasts a similar economic outlook to that
contemplated in the September 2009 Church Forecast ('09 Forecast). In the aftermath of the slowdown
in housing and overall construction, Idaho's employment numbers are expected to post significantly
reduced totals through the IRP period. On a brighter note, the non-ag employment sector is expected to
show higher annual growth rates in the 11 Forecast compared to the '09 Forecast.
In the '11 Forecast, nonagricultural employment in Idaho is projected to grow at an annual rate of 2.28%
over the 2013 - 2017 IRP period. This is a higher rate than the 2.09% annual growth rate projected in the
'09 Forecast. As described above, the non-ag jobs total in the 11 Forecast ranges from 45,000 to 54,000
fewer jobs fewer than projected in the '09 Forecast.
Manufacturing employment exhibits similar behavior. The 2012 IRP-period annual growth rate here is
2.1% compared to a 0.66% rate in the '09 Forecast. On the other hand, in the 11 Forecast annual
Manufacturing totals lag the annual '09 Forecast figures by 9,000 to 11,000 jobs, a 12 - 15% deficit.
Projections of the 2012 IRP-period population growth in Idaho remain fairly consistent in the 11 Forecast
compared to the '09 Forecast. In the newer forecast, Idaho's total population is forecasted to grow from
the estimated figure of 1,618,000 at the beginning of 2013 to 1,767,530 by the end of 2017, an annual
growth rate of 1.79%. The earlier forecast across the same period showed Idaho's population growing
from an estimated figure of 1,594,000 at the beginning of 2013 to a slightly smaller figure of 1,743,000 in
2017, a higher annual growth rate of 1.81%. The number of future households projected in the State is
similarly lower in the '11 Forecast.
The High and Low Economic Growth Scenarios
The high growth and low growth scenarios of the '11 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
vision of a more rapidly growing economy in Idaho. For example, the high growth scenario produces a
projected statewide population of nearly 1,873,500 in the year 2017 versus a base scenario Idaho
population forecast of 1,767,530 in the same year. The high growth scenario average annual compound
rate of population growth is 2.52% per year.
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2013-2017 Integrated Resource Plan
Alternatively, the low growth scenario of the '11 Forecast presents a slower economic outlook for the
Idaho economy. In the low growth scenario, Idaho's 2017 population is projected to reach the much
lower level of 1,639,800, exhibiting an annual average compound growth rate of 0.82% 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 '11 Forecast.
In the high growth scenario of the '11 Forecast, total Non-Agricultural employment is predicted to grow by
100,520 jobs, compared to 75,450 in the base case. Therefore, in spite of the employment losses that
the State has experienced in this economic downturn, Idaho's job market is expected to expand in the
future. Fifty-one percent of the Non-Ag jobs added in the high growth scenario will be in Information,
Financial Activities, Professional and Business Services, and Educational and Health Services. This
proportion is very similar to that in the base case. Manufacturing in the high case will make up less than
8% of the 2013-2017 job growth. In the base case, Manufacturing job growth is slightly over 8% for the
period.
In the low growth scenario of the '11 Forecast, total Non-Agricultural employment is predicted to grow by
47,700 jobs, compared to 75,450 in the base case. As in the high and base cases, in spite of the slower
economic recovery outlook in the low case, Idaho's job market is expected to expand in the future. Of the
Non-Ag jobs added in the low growth scenario, 53% will be in Information, Financial Activities,
Professional and Business Services, and Educational and Health Services. Manufacturing in the low
case will also make up about 8% of the 2013-2017 job growth.
The following graphs illustrate the relationship between the three economic scenarios for the annual total
households forecast and the annual additional households forecast for the IGC Service Territory counties.
IANNUAL ADDITIONAL HOUSEHOLDS FORECASTI
14,000
12,000
10,000
8,000
6,000
4,000
2,000
FY13 FY14 FY15 FY16 FY17
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2013-2017 Integrated Resource Plan
ANNUAL ADDITIONAL HOUSEHOLDS FORECAST
2012 IRP VS 2010 IRP
10,000
8,000
2O12 IRP
-*-2OIOIRP
6,000
FY13 FY14 FY15
IANNUAL TOTAL HOUSEHOLDS FORECASTI
510,000
495,000
480,000
465,000
450,000
435,000
420,000
FY13 FY14 FY15 FY16 FY17
--HIGH GROWTH
-.-BASE CASE
-k-LOW GROWTH
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2013-2017 Integrated Resource Plan
ANNUAL TOTAL HOUSEHOLDS FORECAST
2012 IRP VS. 2010 IRP
480,000
470,000
460,000 -*-2010 IRP
--2012 IRP
450,000
440,000
430,000
FY13 FY14 FYI
Market Share Rates
IGC utilizes market penetration rates that vary across the service territory. These regional penetration
rates are applied to Intermountain's service-territory counties within three specific regions: west, central,
and east. Penetration rates are the ratio of IGC's additional residential new construction customers to the
total building permits in those regions. The forecast of additional households, per the 11 Forecast,
multiplied by the regional market penetration rate equals the anticipated residential new construction
customers.
IGC develops market penetration rates by way of the county construction reports which Intermountain'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 these reports, to derive the market penetration rate. The areas covered here are the major
population centers in the IGC Service Territory: Ada/Canyon County, Twin Falls/Wood River Valley,
Pocatello/Soda Springs, and Idaho Falls/Rexburg. Market penetration rates are derived month by month.
The same set of market penetration rates was used in the baseline, high growth, and low growth
scenarios.
MARKET PENETRATION RATES
FY13 FY14 FY15 FY16 FY17
Western Region 97% 97% 97% 97% 97%
Central Division 98% 98% 98% 98% 98%
Eastern Region 86% 86% 86% 86% 86%
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2013-2017 Integrated Resource Plan
The following graph illustrates the relationship between the three economic scenarios for the annual
residential new construction growth forecast for 2013 - 2017:
IANNUAL RESIDENTIAL NEW CONSTRUCTION GRW
I 6,000
I 4,000
I 2,000
o
FY13 FY14 FY15 FY16 FY17
IANNUAL RESIDENTIAL NEW CONSTRUCTION GROWTH
2012 IRP VS 2010 IRP
I 5,000
-*-2010 IRP
2O12 IRP
I 4,000
3,000
FY13 FY14 FY15
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2013-2017 Integrated Resource Plan
RESIDENTIAL CONVERSION CUSTOMERS
The conversion market represents another source of customer growth. IGC acquires these customers
when homeowners replace an electric, oil, coal, wood, or other alternate fuel source furnace/water heater
with a natural gas unit. IGC forecasts these customer additions by applying regional conversion rates
based on historical data and future expectations. The following table shows, by region the assumed
conversion rates over the five-year period. These rates represent the percentage of new construction
additions which will be conversions.
REGIONAL CONVERSION RATES
FY13 FY14 FY15 FY16 FY17
Western Region
Base Case 11% 11% 11% 11% 11%
High Growth 11% 11% 11% 11% 11%
Low Growth 11% 11% 11% 11% 11%
Central Region
Base Case 23% 23% 23% 23% 23%
High Growth 23% 23% 23% 23% 23%
Low Growth 23% 23% 23% 23% 23%
Eastern Division
Base Case 19% 19% 19% 19% 19%
High Growth 19% 19% 19% 19% 19%
Low Growth 19% 19% 19% 19% 19%
The following graphs illustrate the relationship between the three economic scenarios for the annual
residential conversion growth forecast for 2013 - 2017:
IANNUAL RESIDENTIAL CONVERSION GROWTH I
-Iii
600
I 400
I 200
FY13 FY14 FY15 FY16 FY17
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2013-2017 Integrated Resource Plan
ANNUAL RESIDENTIAL CONVERSION GROWTH
2012 IRP VS 2010 IRP
800
700
I 600
--2010 IRP
-1-2012 IRP
500
400
FY13 FY14 FY15 I
SMALL COMMERCIAL CUSTOMERS
Small commercial customer growth is forecast as a certain proportion of new construction customer
additions. The logic being that as household growth drives the major proportion of IGC's residential
customer growth, household growth therefore drives small commercial customer growth. New
households require additional new businesses to serve them. Based on the most recent three-year sales
data, this ratio of small commercial customer growth to residential growth for the West, Central, and East
was 6.80%, 11.59%, and 11.97%, respectively. Therefore, regional ratios of 7% for the West, and 12%
for Central and East are used in the Base, High, and Low Scenarios.
The following graphs show the annual additional, as well as the annual total small commercial customers
for the period 2013-2017:
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IANNUAL ADDITIONAL SMALL COMMERCIAL CUSTOMERSI I
600
I 400
-HIGH GROWTH
-s-BASE CASE
-*-LOW GROWTHJ
200
0
13 FY14 FY15 FY16 F
ITOTAL ANNUAL SMALL COMMERCIAL CUSTOMERS I
32,000
31,000
30,000
29,000
13 FY14 FY15 FY16 F
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The next graph illustrates the difference in the annual small commercial customer growth forecasts
between the 2010 IRP and the 2012 IRP for thA var tnmmnn to both qtiidis
ANNUAL ADDITIONAL SMALL COMMERCIAL CUSTOMERS
2012 IRP VS 2010 IRP
I 800
I 600
-*-2010 IRP
-0-2012 IRP
I 400
I 200
FY13 FY14 FY15
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2013-2017 Integrated Resource Plan
HEATING DEGREE DAYS AND DESIGN WEATHER
Intermountain's demand forecast captures the influence weather has on system loads by utilizing Heating
Degree Days (HDD's). HDD'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. HDD values are inversely related
to temperature meaning that as temperatures decline, HDD's increase. The standard HDD base, and the
one Intermountain utilizes in its IRP, is 65°F (also called HDD65). As an example, if one assumes a day
where the mean outdoor temperature is 30°F, the resulting HDD65 would be 35 (i.e. 65°F base minus the
30°F mean temperature = 35 Heating Degree Days). Two distinct groups of heating degree days are
used in the development of the IRP: Normal Degree Days and Design Degree Days.
Since Intermountain's service territory is composed of a diverse geographic area with differing weather
patterns and elevations, Intermountain uses weather data from seven NOAA weather stations located
throughout the communities in its service territory. This weather data is "weighted" by the customers in
each of the geographic weather districts to arrive at weighted weather for the entire company. Several
distinct distribution segments are also addressed specifically by this IRP. Those segments are assigned
unique degree days as discussed in further detail below.
NORMAL DEGREE-DAYS
A Normal Degree Day is calculated based on historical data, and represents the weather that could
reasonably be expected to occur on a given day. The Normal Degree Day that Intermountain utilizes in
the IRP is computed based on weather data for the thirty years ended December 2010. The HDD65 for
January 1st for each year of the thirty year period is averaged to come up with the average HDD65 for the
thirty year period for January 1st. This method is used for each day of the year to arrive a year's worth of
Normal Degree Days.
DESIGN DEGREE-DAYS
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.
Intermountain's design year is based on the premise that the coldest weather experienced for any month,
season or year could occur again. The basis of a design year was determined by evaluating the weather
extremes over the last thirty years of heating degree day data from NOAA. The review revealed
lntermountain's coldest twelve consecutive months to be the 1984/1985 heating season (October 1984
through September 1985). That year, with certain modifications discussed below, represents the base
year for design weather. These degree days reflect a set of temperature extremes that have actually
occurred in Intermountain's service area. These extreme temperatures would result in a maximum
customer usage response due to the high correlation between weather and customer usage.
Intermountain also engaged the services of Dr. Russell Quails, Idaho State Climatologist, to perform a
review of the methodology used to calculate design weather, and to provide suggestions to enhance the
design weather planning. One crucial area that Dr. Quails was able to assist Intermountain in was
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 fitted probability
distributions to thirty years of daily temperature data from seven weather station locations (Caldwell,
Boise, Hailey, Twin Falls, Pocatello, Idaho Falls and Rexburg). From these distributions he calculated
monthly and annual minimum daily average temperatures for each weather location, corresponding to
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2013-2017 Integrated Resource Plan
different values of exceedance probability. Two probability distributions were fitted, a Normal Distribution,
and a Pearson Type ill (P3) distribution. Dr. Quails suggested it is more appropriate for Intermountain to
use the P3 distribution as it is more conservative from a risk reduction standpoint.
According to Dr. Quails, "selecting design temperatures from the values generated by these probability
distributions is preferable over using the coldest observed daily average temperatures because
exceedance probabilities corresponding to values obtained from the probability distributions are known.
This enables IGC to choose a design temperature, from among a range of values, which corresponds to
an exceedance probability that IGC considers appropriate for the intended use".
Intermountain used Dr. Quails' exceedance probability data to review the data associated with both the
50 and 100 year probability events. After careful consideration of the data, Intermountain determined that
the company-wide 50 year probability event, which was an 81 degree day, would be appropriate to use
for our design weather model. For modeling purposes, this 81 degree day was assumed to occur on
January 15th
Base Year Design
To create a design weather year from the base year, a few adjustments were made to the base design
year. First, since the coldest month of the last thirty years was December 1985 (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 was placed on January 15th.
To model the days surrounding the peak event, Dr. Quails suggested calculating a 5-day moving average
of the temperatures for the thirty year period to select the 5 coldest consecutive days from the period.
December 1990 contained this cold data. The coldest day of the peak month (December 1985) was
replaced with the 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 Demand 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 the 1985 heating year was the coldest 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. 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 Degree Day Graph below). This curve provides a robust projection of the
extreme temperatures that can occur in Intermountain's service territory.
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2013-2017 Integrated Resource Plan
1800
1600
1400
1200
1000
800
0 600
400
200
0
0'/ S
Degree Day Graph
+4 S
Months
The resulting Normal, Base Year, and Design Year degree days by month are outlined in the following
table:
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2013-2017 Integrated Resource Plan
AREA SPECIFIC DEGREE DAYS
In the 2010 IRP, Intermountain noted unique characteristics of certain areas of its distribution system.
These are areas Intermountain carefully manages to ensure adequate delivery capabilities either due to a
unique geographic location, customer growth, or both. The areas Intermountain is currently monitoring
include the Idaho Falls Segment, the Sun Valley Segment, the State Street Segment, and the Canyon
County Segment.
The temperatures in these areas can be quite different from each other and from the Total Company. For
example, the temperatures experienced in Idaho Falls or Sun Valley can be significantly different from
those experienced in Boise or Pocatello. Intermountain continues to work on improving its capability to
uniquely forecast loads for these distinct areas. A key driver to these area specific load forecasts is area
specific heating degree days.
Intermountain has developed Normal and Design Degree Days for each of the segments. The methods
employed to calculate the Normal and Design Degree Days for each of these segments mirrors the
methods used to calculate Total Company Normal and Design Degree Days. Having distinct weather for
these areas 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.
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2013-2017 Integrated Resource Plan
USAGE PER CUSTOMER
For the IRP planning process, core market usage per customer is calculated in three segments. First, the
critical winter heating season and particularly the peak day usage per customer is calculated using daily
usage formulas. Next, the less weather sensitive, non-peak usage per customer is calculated on a
monthly basis. Finally, usage per customer is evaluated for the distribution system segments to see if
customers use natural gas differently in those areas.
CUSTOMER USAGE DURING PEAK MONTHS
The peak heating season for Intermountain Gas Company is November through February. Because the
relationship between weather and usage is so strong during these winter months, it is possible to develop
statistically significant daily usage per customer equations. Multiple regression equations were
developed for each of the four winter months as outlined in the following section.
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 efficiency 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", Page 67).
All of these conservation influences began impacting usage in the early 1990's. Since roughly 65% 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 Intermountain's
usage per customer, and contributing to the structural changes we have seen in the data. Finally, Idaho's
economic downturn has impacted usage per customer. The increased number of foreclosures and
vacant homes, coupled with less money in family budgets for energy expenditures has put additional
downward pressure on usage per customer numbers.
To account for these structural shifts in the data, Intermountain used a time series beginning with the
winter of 2000/2001 through the winter of 2010/2011 to develop the regression peak month equations.
Dependent Variable - Daily Usage Per Customer
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 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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2013-2017 Integrated Resource Plan
Intermountain would like to be able to test whether or not models developed for each individual customer
class would perform better for predicting peak usage per customer than models developed using total
core market data. Since its current technology does not allow for the necessary daily meter reads,
Intermountain investigated options that would enable the collection of daily usage data by core market
customer class. Current technology requires that the meters' ERT units be read daily to collect daily data.
This method of data collection is 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 process.
These units would collect daily data that could then be downloaded as part of the normal monthly meter
reading process. Intermountain will 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 will continue to collect daily core market sendout which enables a daily core market usage
calculation.
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.Intermountain Gas "Weighted Average Cost of Gas" (WACOG)
4.Consumer Price Index
5.Bank Prime Loan Rate
6.30-Year Conventional Mortgage Rate
7.Gross Domestic Product
8.Idaho Per Capita Personal Income
9.Number of persons per household (county specific)
10.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 November, the statistically
significant independent variables included in the model to explain changes in daily usage per customer
are; daily actual 65HDD and IGC WACOG. In December, the sole explanatory variable that is significant
is 65HDD. The January and February models, include; daily actual 65HDD and a weekend binary
variable (see "Regression Equations," Exhibit 2, Appendix A).
Each of the selected models meets accepted standards for statistical soundness. The models all have
high R2 statistics which determine the percent of the variability in usage per customer that is explained by
the independent variables. T-statistics for each of the variables indicate they are individually significant
(p0.05). 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.
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.
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 month usage models. The dramatically different 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 capability to collect daily usage by customer class. Therefore,
the Non-Peak month models begin as monthly usage models.
Intermountain Gas Company
2013-2017 Integrated Resource Plan
Variable Selection
Time Series
Intermountain has developed a database of historical monthly data going back to 1981. All three
customer class models were tested 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, 2001 forward, and 2003 forward.
Intermountain found that the time series 2003 forward provided the best statistical fit for all three
customer classes. This time series accounts for the structural shifts in the data based on building and
efficiency factors, as well as the new market environment brought about by the economic downturn.
Dependent Variable - Monthly 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.
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.Percent price change year over year
7.Consumer Price Index
8.Bank Prime Loan Rate
9.30-Year Conventional Mortgage Rate
10.Gross Domestic Product
11.Idaho Per Capita Personal Income
12.Idaho Housing Starts
13.Average home sales price
14.Days on the market for home sales
15.Usage Trends (both annual and winter only)
Methodology and Results
A regression equation was developed for each of the three Core market customer classes. The models
are all similar in structure in that the 65HDD variable and a trend variable were significant in each case.
The RS-1 and GS models use an annual trend variable while the RS-2 model uses a winter only trend
variable (see "Regression Equations," Exhibit 2, Appendix A).
Each of the selected models meets accepted standards for statistical soundness. The models all have
high R2 statistics which determine the percent of the variability 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.
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2013-2017 Integrated Resource Plan
Since the models calculate 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.
TOTAL DAILY USAGE
For both peak and non-peak periods, 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.
Total daily usage varied depending upon the customer growth assumption that was used (i.e. low growth,
baseline, or high growth).
USAGE PER CUSTOMER BY GEOGRAPHIC AREA
In a service territory as geographically and economically diverse as Intermountain's, we recognize that
there could be significant differences in the way customers use natural gas based upon their location on
the distribution 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.
Canyon County and State Street Lateral Segments
The locations of both the Canyon County and State Street lateral segments 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
distribution system segments.
As the "Heating Degree Days and Design Weather" section outlines, Intermountain has developed
Normal and Design Degree Days for both the Canyon County and the State Street lateral segments. The
total company usage per customer equations were applied to these area specific degree days to provide
a unique usage forecast that will more accurately predict the loads for both Canyon County and the State
Street Lateral segments.
Sun Valley Lateral Segment
Variable Selection
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
malfunction, 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.
Since Intermountain had these difficulties with the data collecting meters, telemetry equipment was
installed that sends the data directly to Intermountain. The data is stored in a database that is regularly
backed up, so no additional problems with data loss have occurred. Thus, the final dataset represents
seven 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
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
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Intermountain Gas Company
2013-2017 Integrated Resource Plan
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) for each day during the peak months
2.Intermountain Gas natural gas prices
3.Intermountain Gas WACOG
4.Consumer Price Index
5.Bank Prime Loan Rate
6.30-Year Conventional Mortgage Rate
7.Gross Domestic Product
8.Idaho Per Capita Personal Income
9.Number of persons per household (county specific)
10.A weekend binary variable to establish whether or not a relationship exists between usage levels
and the weekend.
11.Daily snowfall totals
12.Daily snow depth
Methodology and Results
A peak day regression equation was tested for the Sun Valley segment that included data for the
traditional peak month of January 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.
Although Intermountain now has an interruptible tariff for snow melt equipment in the Sun Valley area,
daily snowfall remains a valid explanatory variable, because existing snow melt equipment was
grandfathered on its existing rate schedule at the time the interruptible tariff was adopted. As growth
makes existing snow melt a smaller portion of the firm load requirement, Intermountain will monitor the
data to see if snowfall continues to make sense as an explanatory variable.
As discussed in the "Heating Degree Days and Design Weather" section, Intermountain calculated lateral
specific design degree days which were applied to the Sun Valley lateral regression formula. To
calculate peak snowfall, Intermountain looked back over the actual snowfall data from 1990 through 2011
and identified 22 inches as the maximum daily snowfall total. That actual peak amount was applied to the
regression formula. The usage per customer resulting from the regression formula was multiplied by Sun
Valley lateral customers to arrive at total usage for the segment.
Idaho Falls Lateral Segment
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
malfunction, data was lost for the 2005/2006 winter. Since that time, telemetry equipment has also been
installed on this meter. The data is sent directly to an Intermountain database and regularly backed up to
prevent data loss from occurring in the future. With the loss of the 2005/2006 data, the final dataset
represents six years of data.
Dependent Variable - Daily Usaae 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
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Intermountain Gas Company
2013-2017 Integrated Resource Plan
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) for each day during the peak months
2.Intermountain Gas natural gas prices
3.Intermountain Gas WACOG
4.Consumer Price Index
S. Bank Prime Loan Rate
6.30-Year Conventional Mortgage Rate
7.Gross Domestic Product
8.Idaho Per Capita Personal Income
9.Number of persons per household (county specific)
10.A weekend binary variable to establish whether or not a relationship exists between usage levels
and the weekend.
Methodology and Results
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 as well as
regressions for the peak month of January alone. Daily actual HDD65 were significant in explaining
changes in usage per customer. The overall statistics for these models were not strong, however, and
the resulting equation did a poor job of forecasting usage based on actual conditions.
Intermountain's commitment to providing safe, reliable service on a peak day required the use of an
alternate method to forecast peak day load. Intermountain next looked at an average usage per
customer per degree day. This method forecast usage on a peak day on the Idaho Falls lateral that 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 the total company equation with segment
specific degree days to forecast peak day loads on the Idaho Falls lateral segment.
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INDUSTRIAL FORECAST
INTRODUCTION
Intermountain sent a survey to all of its large-volume contract (or "Industrial") customers early in 2011.
Analysis of the completed surveys was competed in the spring of 2011 and the data was used to help
project each customer's future natural gas usage. The survey included a cover letter explaining the
intended use of the requested information with the assurance that all responses would remain
confidential. The data form, sent to the management of each of Intermountain's large-volume contract
customers, identified historical usage on an annual, peak month and peak day basis for the two years
ending December 2010. That data was supplied to provide an historical basis to assist each customer in
analyzing current usage and forecasting how future natural gas requirements may change. Additional
information was requested as to the availability of alternative fuel capabilities and if there was a desire for
additional service options from Intermountain.
The results of the survey were considered along with other information obtained via on-site visits and
other discussions with the customers' management, engineers, and marketing personnel regarding plant
expansion or modification, equipment replacement, and anticipated product demand. This information
was used to develop Intermountain's Base Case industrial sales forecast. After the Base Case was
complete, additional data, including high and low economic forecasts, was utilized to adjust the survey
base data in order to develop the High Demand and Low Growth scenarios. The result was three distinct
five-year industrial usage forecasts.
Intermountain currently has 111 industrial customers. For analysis purposes, these customers were
further filtered into six separate, more homogenous sub-groupings comprised of:
• 18 potato processors
• 34 other food processors including sugar, milk, beef, and seed companies
• 3 chemical and fertilizer companies
• 17 light manufacturing companies including electronics, paper, and asphalt companies
• 29 schools and hospitals
• 10 other companies
All existing customers were assumed to remain on their current tariff. Any new customers using less than
500,000 therms were assumed to be an LV-1 customer while new customers using over 500,000 annual
therms were assumed to be T-4 customers.
HIGH DEMAND FORECAST
The high demand, or most optimistic, forecast incorporates usage data directly from the survey with
adjustments for growth due to favorable economic conditions. The high case forecast starts out
approximately 7.5% above the base case forecast. When compared to the Base Case, the High Demand
projection may not seem to show much growth but in general, recent actual industrial use has been high
due to very favorable market conditions so the Base Case already reflects robust sales. The annual
usage estimate of 265,033,000 therms in 2013 is projected to increase 5,765,000 therms, or 2.2% over
the five year period. The following table summarizes these changes:
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2013-2017 Integrated Resource Plan
High Demand Forecast by Market Segment
(Thousand of Therms i
Compound
Rate of
FY 13 FY 14 FY 15 FY 16 FY 17 Growth
Potato Processors 93,500 94,500 94,500 94,500 94,500 0.27%
Other Food
Processors 71,850 72,360 72,360 72,410 74,810 1.01%
Chemical & Fertilizer 29,950 29,950 29,950 29,950 29,950 0.00%
Manufacturers 18,215 18,615 18,815 19,015 19,415 1.61%
Institutions 20,504 21,376 21,256 21,156 21,058 0.67%
Other 31,014 31,014 31,015 31,015 31,065 0.04%
Total High Demand
Forecast Therm
Sales 265,033 267,815 267,896 268,046 270,798 0.54%
A.In the high demand scenario, Potato Processing is up from the 2010 IRP projections, and the
future looks steady for the potato industry. This scenario shows the processors volumes flat
because current usage levels are at record high levels. However, the near-record potato crop in
2011 is a two edge sword for potato processors: great quality and yield but lower prices. Under
the High Demand scenario, natural gas prices are expected to stay steady and competitive with
alternative fuels low which would encourage plants to use gas rather than oil.
B.Other Food Processors are projected to be flat across the reporting period again at record high
levels. The addition of a large yogurt producer and a projected additional cheese plant in the
Burley/Rupert area should make up for any production fall-off by other processors. Those plants
dealing with cattle are optimistic for steady increases in output, while the loss of one meat
processor is a dampener.
C.The Chemical/Fertilizer group is projected to be flat with no new production facilities added. The
three existing plants project steady production and usage at high levels.
D.The Manufacturing group is projected to show an increase over the period with the addition of two
new manufacturing plants - one in the high tech industry and the other an asphalt producer.
E.The Institutional group, which is made up mostly of schools and hospitals, is projected by the
survey to grow slowly with increased usage at a few facilities.
F.The Other group is projected to grow slightly, with some increased usage at a greenhouse, and
the addition of a new user. Usage will be relatively flat across the reporting period in the high
case.
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Intermountain Gas Company
2013-2017 Integrated Resource Plan
BASE CASE FORECAST
Again, the Base Case was compiled using the customer surveys as a base with added adjustments to
reflect known changes of existing customers. The projected usage for the Base Case increased by
3,365,000 therms across the five-year period, amounting to 0.33% growth rate.
Base Case Forecast by Market Segment
(Thousands of Therms)
Compound
Rate of
FY 13 FY 14 FY 15 FY 16 FY 17 Growth
Potato Processors 88,500 89,500 89,500 89,500 89,500 0.28%
Other Food
Processors 69,315 69,825 69,825 69,875 69,875 0.16%
Chemical & Fertilizer 24,950 24,950 24,950 24,950 24,950 0.00%
Manufacturers 17,240 17,640 17,840 18,040 18,440 1.70%
Institutions 19,879 20,751 20,631 20,531 20,433 0.69%
Other 30,014 30,014 30,015 30,015 30,065 0.04%
Total Base Case
Forecast Therm
Sales 249,898 252,680 252,761 252,911 253,263 0.33%
A.The Potato Processors group is forecast to show very slow growth over the five year period.
Demand for potato products is steady, and the supply is good. No new plants are planned over
the forecast period. Most of the plants in this group are looking for ways to conserve resources
while maximizing production, thus lowering the overall cost of production.
B.The Other Food Processors group is projected to be relatively flat over the period.
C.The three plants in the Chemicals/Fertilizers group will continue at current levels with no
projected growth or production increases in the forecast. In their forecasts, the managers of
these plants assume imported fertilizers will not, at least in the foreseeable future, negatively
affect their operations.
D.The Manufacturing group is expected to grow somewhat. Proposed plant expansions might
increase manufacturing further.
E.The Institutional group is projected to grow at 0.69% a year, mainly due to BYU-Idaho converting
coal boilers over to natural gas.
F.The usage in the Other group is also projected to be relatively flat over the period.
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Intermountain Gas Company
2013-2017 Integrated Resource Plan
Low GROWTH SCENARIO
The projected usage for this scenario is based upon the assumption that the agricultural economy will be
somewhat difficult with very little growth in sales and production. It is also assumed that natural gas
prices will increase slightly but remain reasonably competitive. With those assumptions, no segment
downturns are projected. The low growth scenario projections start 2% below the base case in 2013 with
an overall growth rate of 0.21% over the period, as shown below.
Low Growth Forecast by Market Segment
(Thousand of Therms)
Compound
Rate of
FY 13 FY 14 FY 15 FY 16 FY 17 Growth
Potato Processors 88,275 89,275 89,275 89,275 89,275 0.28%
Other Food
Processors 66,315 65,385 65,385 65,435 65,435 (0.33)%
Chemical &
Fertilizer 23,338 23,338 23,338 23,338 23,338 0.00%
Manufacturers 17,035 17,435 17,635 17,835 18,235 1.72%
Institutions 19,554 20,456 20,381 20,306 20,233 0.84%
Other 30,014 30,014 30,015 30,015 30,065 0.04%
Total Low Growth
Forecast Therm
Sales 244,531 245,903 246,029 246,204 246,581 0.21%
A.The Potato Processor group, as a whole, looks at any way possible to conserve energy and make
its plants more efficient. The price of natural gas was assumed to be competitive against the
delivered price of oil over the five-year forecast and consequently, gas sales are assumed to
remain at current levels.
B.The Other Food Processor group's usage is expected to decline, reflecting less raw product.
C.The projection for the Chemical/Fertilizer group remains flat with no increase or decrease in
usage or production.
D.The Manufacturing group is also projected to increase over the period by 1.7% although starting
1.1% below the base case. The scenario assumes that no additional "High Tech" production
occurs and no state or federal highway projects begin.
E.The flat growth projection for the Institutional group in the low growth forecast is attributed to no
known expansion of universities, schools, and hospitals.
F.Facilities in the Other group are projected to increase slightly, mainly due to some increased
usage at a greenhouse facility.
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Intermountain Gas Company
2013-2017 Integrated Resource Plan
FIRM CONTRACT DEMAND
The survey sent to the industrial customers 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 usage may not increase, their off-peak day requirements could grow, due in part to their use of
varying work schedules.
While Intermountain calculates a "load-profile" forecast for these customers, it does not utilize these
figures for IRP modeling purposes. Instead, the individual customers' contractual Maximum Daily Firm
Quantities (MDFQ) are used to determine peak day demand requirements. This is because IGC agrees
to reserve capacity equal to the customer's MDFQ each and every day of the year. Therefore each
customers MDFQ requirement is assumed to remain constant for each day of the planning period.
Intermountain has several classes of industrial service. LV-1 customers have contracted for firm sales U
service with Intermountain meaning that natural gas is delivered directly to their facility. Intermountain
includes the LV-1 customer's MDFQ when calculating the requirements for gas supply and interstate
pipeline capacity as well as distribution system capacity. Service to LV-1 customers is limited to 500,000
therms per year.
Transportation customers (T-3, T-4, and T-5) do not purchase their natural gas or interstate transportation
capacity from Intermountain but only contract for distribution system capacity. These customers assume
the responsibility to purchase natural gas and provide interstate pipeline capacity. All transport
customers currently utilize a marketing agent to perform these functions on their behalf. The marketers
arrange to deliver natural gas to Intermountain's distribution system which is in turn re-delivered to their
facility. The firm transportation classes (T-4 and T-5) are included when calculating distribution system
capacity needs. Because T-3 is interruptible service, Intermountain does not include their MDFQ when
analyzing distribution system needs.
The total Industrial MDFQ has increased 9.3% over the 2010 IRP filing.
Seuments
Large Volume Firm Sales Services (LV-1)
Firm Transportation Services
Total
Total MDFQ Requirements
(Therms)
15,650
949,122
964,772
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Intermountain Gas Company
2013-2017 Integrated Resource Plan
LOAD DEMAND CURVES
The culmination of the demand forecasting process is aggregating the information discussed in the
previous sections into a forecast of future load requirements. As the previous sections illustrate, the
customer forecast, design weather, core usage data, industrial usage forecast and price scenarios are all
key drivers in the development of the load demand curves.
The IRP customer forecast provides a total company daily projection through Planning Year (PY) 2017
and includes a forecast for each of the four regional segments of the distribution system. Each forecast
was developed under each of three different customer growth scenarios: base case, high growth and low
growth. Additionally, three distinct pricing scenarios were created: base price, low price, and high price.
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
Intermountain's load on a daily basis. Applying Design Weather to the residential and small commercial
usage per customer forecast creates core market usage-per-customer under design weather conditions.
That combined with the applicable customer forecast and price scenarios yields a daily core market load
projection through PYI 7 for company total as well as for each regional segment. Similar normal weather
scenario modeling was also completed.
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.
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-low to create what is known as a Load Demand Curve (LDC). The LOG incorporates
all the factors that will impact Intermountain's future loads. The LDC is the basic tool used to reflect
demand in the IRP Optimization Model.
It is important to note that the Load Demand Curves represent existing resources and are intended to
identify potential capacity constraints and to assist in the long term planning process.
DESIGN PY 13- PY 17 CUSTOMER GROWTH SUMMARY OBSERVATIONS
Idaho Falls Lateral
The Low Growth customer forecast projects an increase in customers of 2,591 through PYI7 (Oct 1,
2012 to Sep 30, 2017) which corresponds to an annualized average growth rate of 1.05%. Base Case
customers increase by 4,701 customers (1.09%) and High Growth customers increase by 6,611
customers (1.13%). When comparing the PYI3 Base Case customer starting point (Oct. 1) of the 2010
LDC to the current LDC, there is a decrease of 2,474 Base Case customers.
Sun Valley Lateral
The Low Growth customer forecast (PYI 3 - PYI 7) projects an increase of 76 customers (1% annualized
growth rate), Base Case customer forecast increases by 369 customers (1.03% annualized growth rate),
and High Growth customer forecast shows an increase of 626 customers (1.06% annualized growth rate).
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Intermountain Gas Company
2013-2017 Integrated Resource Plan
When comparing the PYI3 Base Case customer starting point (Oct. 1) of the 2010 LOC to the current
LDC, there is a decrease of 215 Base Case customers.
Canyon County Area
The Low Case customer Forecast for Canyon County (CC) reflects an increase of 3,967 customers during
this IRP period (PYI3 - PYI7), which is an annualized growth rate of 1.08%. The Base Case customer
forecast for CC increases by 4,866 customers (1.11% annualized growth rate) over the 5-year period.
The High Growth customer forecast shows an increase of 5,923 customers (1.13% annualized growth
rate). When comparing the PYI 3 Base Case customer starting point (Oct. 1) of the 2010 LDC to the
current LDC, there is a decrease of 1,808 Base Case customers.
State Street Lateral
The Low Case customer Forecast for the State Street Lateral (SSL) reflects an increase of 1,277
customers during this IRP period (PYI3 - PYI7), which is an annualized growth rate of 1.03%. The Base
Case customer forecast for SSL increases by 2,402 customers (1.05% annualized growth rate) over the
5-year period. The High Growth customer forecast shows an increase of 3,520 customers (1.08%
annualized growth rate). When comparing the PYI3 Base Case customer starting point (Oct. 1) of the
2010 LDC to the current LDC, there is a decrease of 821 Base Case customers.
Total Company
The Low Growth customer forecast (PYI3 - PYI7) projects an increase of 14,438 customers (1.05%
annualized growth rate), the Base Case customer forecast increases by 24,075 customers (1.08%
annualized growth rate), and the High Growth customer forecast shows an increase of 33,712 customers
(1.11% annualized growth rate). When comparing the PYI 3 Base Case customer starting point (Oct. 1) of
the 2011 LDC to the current LDC, there is a decrease of 5,434 Base Case customers.
Using the LDC analyses, Intermountain will 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 demand 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 scenario. 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
scenarios for comparison. These scenarios were run using both 'Design' and 'Normal' weather for the
Idaho Falls, State Street, Sun Valley, and Canyon County segments, as well as the aggregate scenario.
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2013-2017 Integrated Resource Plan
Idaho Falls
Idaho Falls Lateral Design Weather- Total Annual Usage (Dth)
Growth Scenario Price Scenario 2013 2014 2015 2016 2017
Low High 7,446,971 7,481,696 7,518,553 7,549,496 7,576,528
Base Base 7,453,991 7,551,230 7,657,809 7,759,451 7,858,866
High Low 7,458,721 7,607,644 7,771,764 7,933,150 8,095,626
Idaho Falls Lateral Normal Weather- Total Annual Usage (Dth)
Growth Scenario Price Scenario 2013 2014 2015 2016 2017
Low High 6,584,505 6,613,774 6,644,750 6,670,599 6,692,899
Base Base 6,590,793 6,675,243 6,767,874 6,856,300 6,942,436
High Low 6,595,163 6,725,233 6,868,750 7,010,061 7,152,015
Sun Valley
Sun Valley Lateral Design Weather- Total Annual Usage (Dth)
Growth Scenario Price Scenario 2013 2014 2015 2016 2017
Low High 1,750,282 1,751,797 1,755,966 1,761,613 1,765,576
Base Base 1,751,224 1,759,161 1,773,193 1,786,511 1,803,500
High Low 1,752,876 1,766,594 1,789,355 1,815,556 1,838,333
Sun Valley Lateral Normal Weather- Total Annual Usage (Dth)
Growth Scenario Price Scenario 2013 2014 2015 2016 2017
Low High 1,518,693 1,519,618 1,522,862 1,529,583 1,530,421
Base Base 1,519,533 1,526,052 1,537,841 1,546,629 1,563,352
High Low 1,521,012 1,532,564 1,551,940 1,569,697 1,593,681
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2013-2017 Integrated Resource Plan
Canyon County
Canyon County Area Design Weather- Total Annual Usage (Dth)
Growth Scenario Price Scenario 2013 2014 2015 2016 2017
Low High 5,421,302 5,465,362 5,522,265 5,581,641 5,645,634
Base Base 5,425,025 5,502,237 5,587,396 5,679,647 5,779,687
High Low 5,426,524 5,521,689 5,625,167 5,737,413 5,862,701
Canyon County Area Normal Weather- Total Annual Usage (Dth)
Growth Scenario Price Scenario 2013 2014 2015 2016 2017
Low High 4,665,556 4,701,303 4,747,830 4,796,493 4,849,069
Base Base 4,669,342 4,733,969 4,805,218 4,883,135 4,966,370
High Low 4,670,869 4,751,030 4,838,109 4,932,670 5,038,334
State Street
State Street Lateral Design Weather- Total Annual Usage (Dth)
Growth Scenario Price Scenario 2013 2014 2015 2016 2017
Low High 5,503,623 5,521,490 5,535,726 5,548,562 5,561,442
Base Base 5,505,920 5,548,260 5,590,022 5,630,814 5,672,006
High Low 5,508,500 5,574,023 5,642,157 5,710,890 5,779,883
State Street Lateral Normal Weather- Total Annual Usage (Dth)
Growth Scenario Price Scenario 2013 2014 2015 2016 2017
Low High 4,881,628 4,896,233 4,907,491 4,917,680 4,927,765
Base Base 4,883,715 4,919,854 4,955,335 4,990,296 5,025,117
High Low 4,886,061 4,942,555 5,001,238 5,060,616 5,120,072
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Intermountain Gas Company
2013-2017 Integrated Resource Plan
Total Company
I Total Company Desiun Weather- Total Annual Usaue (Dth ) I
Price
Growth Scenario Scenario 2013 2014 2015 2.016 2017
Low High 39,868,845 40,035,171 40,218,135 40,385,293 40,541,790
Base Base 39,890,733 40,300,195 40,753,955 41,200,263 41,645,170
High Low 39,992,568 40,538,366 41,221,172 41,901,686 42,594,830
I Total Company Normal Weather- Total Annual Usacie (Dth) 1
Growth Scenario Price Scenario 2013 2014 2015 2016 2017
Low High 33,984,268 34,113,912 34,256,938 34,306,741 34,507,317
Base Base 34,003,263 34,339,513 34,712,858 35,078,262 35,446,082
High Low 34,026,827 34,543,830 35,111,802 35,594,197 36,254,441
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 1.02% (low growth), 1.04% (base case) and
1.07% (high growth), highlighting the need for long-term planning. As this section illustrates, there are no
projected capacity deficits during the IRP planning horizon.
Idaho Falls Lateral LDC Study
When forecast peak day sendout on the Idaho Falls lateral is matched against the existing peak day
distribution capacity (99,000 Dth) in the base price scenario, a peak day delivery deficit does not occur.
IFL - Design Weather Peak Day Deficit Under Existing Resources (Dth)
Scenario/Year 2013 2014 2015 2016 2017
Low Growth 0 0 0 0 0
Base Growth 0 0 0 0 0
High Growth 0 0 0 0 0
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Intermountain Gas Company
2013-2017 Integrated Resource Plan
When forecasted peak day send out on the Sun Valley Lateral is matched against the existing peak day
distribution capacity (20,400 0th), a peak day delivery deficit does not occur.
SVL - Design Weather Peak Day Deficit Under Existing Resources (Dth)
Scenario/Year 2013 2014 2015 2016 2017
Low Growth 0 0 0 0 0
Base Growth 0 0 0 0 0
High Growth 0 0 0 0 0
Canyon County LDC Study
When forecasted peak day send out for the Canyon County region is matched against the existing peak
day distribution capacity (68,000 Dth), a peak day delivery deficit does not occur.
CC Area - Design Weather Peak Day Deficit Under Existing Resources (Dth)
Scenario/Year 2013 2014 2015 2016 2017
Low Growth 0 0 0 0 0
Base Growth 0 0 0 0 0
High Growth 0 0 0 0 0
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 (58,500 0th), a peak day delivery deficit does not occur.
SSL - Design Weather Peak Day Deficit Under Existing Resources (Dth)
Scenario/Year 2013 2014 2015 2016 2017
Low Growth 0 0 0 0 0
Base Growth 0 0 0 0 0
High Growth 0 0 0 0 0
All Other LDC Study
No deficits are projected to occur in any of the locations making up the "All Other" group on
Intermountain's system over the five-year study period.
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Intermountain Gas Company
2013-2017 Integrated Resource Plan
Total Company LDC Study
The Total Company perspective differs from the laterals in that it reflects the amount of gas that can be
delivered to Intermountain via the various resources on the interstate system. Hence, total system
deliveries should provide at least the net sum demand - or the total available distribution capacity where
applicable - of all the laterals/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)
Scenario/Year 2013 2014 2015 2016 2017
Low Growth 115,970 110,783 98,292 87,881 85,598
Base Growth 115,254 107,804 92,857 79,911 75,025
High Growth 113,202 103,810 81,769 66,659 59,511
Intermountain Gas Company
2013-2017 Integrated Resource Plan
TRADITIONAL SUPPLY-SIDE RESOURCES
OVERVIEW
The natural gas marketplace continues to change but lntermountain's commitment to act with integrity to
provide secure, reliable and price-competitive firm natural gas delivery to its customers has not. In today's
energy environment, Intermountain bears the responsibility to structure and manage a gas supply and
delivery portfolio that will effectively, efficiently and with best value meet its customers year-round energy
needs. Intermountain will, through its long-term planning, continue to identify, evaluate and employ best-
practice strategies as it builds a portfolio of resources that will provide the value of service that its
customers expect.
The Traditional Supply Resource section will outline the energy molecule and related infrastructure
resources "upstream" of the distribution system necessary to deliver natural gas to the Company's
distribution system. Specifically included in this definition is the natural gas commodity (or the gas
molecule), various types of storage facilities and interstate gas pipeline capacity. This section will identify
and discuss the supply, storage and capacity resources available to Intermountain and how they may be
employed in the Company's portfolio approach to gas delivery management.
BACKGROUND
The procurement and distribution of natural gas is in concept a straightforward process. It simply follows
the movement of gas from its source through processing, gathering and pipeline systems to end-use
facilities where the gas is ultimately ignited and converted into thermal energy. Natural gas is a fossil fuel;
a naturally occurring mixture of combustible gases, principally methane, found in porous geologic
formations beneath the surface of the earth. It is produced or extracted by drilling into those underground
formations or reservoirs and then moving the gas through gathering systems and pipelines to customers
in often far away locations.
Intermountain is fortunate to be located in between two of the most prolific 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 utilizes storage facilities to
essentially store excess natural gas supply during periods of low customer demand and save it for use
during periods of higher demand.
Intermountain's access to the gas produced in these basins is wholly dependent upon the availability of
pipeline capacity to move that gas from those supply basins to lntermountain'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
The last decade has been one of conflicting 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 built new capacity 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 traditional regional price differentials. At the same time, 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 the drop in production of offshore and
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conventional gas supplies. 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 that shale gas production is not only replacing those declines in other sources but is projected to
increase total annual production levels through 2035.
Increased supplies coupled with softening demand due to the global economic downturn have led lower
natural gas prices and a recent pause in drilling activities. These dynamic swings in the supply and
demand balance 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 volatility along with changes in
national and regional pricing trends.
While natural gas prices continue to exhibit volatility from a both national/global and regional
perspectives, the laws of supply and demand clearly govern the availability and pricing of natural gas.
Recent history shows that periods of growing demand tends to drive prices up which in turn generally
results in consumers seeking to lower consumption. At the same time, producers typically increase
investment in activities that will further enhance production. Thus, falling demand coupled with increasing
supplies tend to swing prices lower. This in turn leads to falling supplies, increased demand and the cycle
begins anew. Finding equilibrium in the market has been challenging for all market participants but at the
end of the day, the competitive market clearly works; the challenge is avoiding huge swings that result in
either demand destruction or financial distress in the exploration and production business.
Shale Gas
As mentioned above, the biggest news in the past decade is the emergence of the technology needed to
produce shale gas. Most forecasts just five years ago predicted a troubling future of flat to shrinking long-
term supply of North American natural gas supply. However shale production has completely changed
the industry. Today reserve and production forecasts predict ample and growing gas supplies through
2035 all because of shale gas. The fact that shale gas is being produced in the mid-section of the US>
has displaced production from more traditional supply basins in Canada and the Gulf Cost. There have
been some perceived environmental issues relating to shale production but most studies indicate that if
done properly, shale gas can be produced safely. Customers now enjoy the lowest prices in years due to
the increased production of shale gas. In short, shale gas is game-changer!
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. Due to pipeline capacity availability
Intermountain does not expect to drastically change its historical purchase patterns. Exhibit No. 4, Map I
shows the largest natural gas producing basins in North America.
Alberta
Alberta supplies are delivered to Intermountain via two Canadian pipelines (TransCanada Alberta or
"Nova" and "Foothills") and two U.S. pipelines (Gas Transmission Northwest "GTN" and Northwest
Pipeline "Northwest") as seen on Exhibit No. 4, Map 2. 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 availability of export gas. The decline is result of producers not being able to adequately
replace the prolific but generally produced reserves and because more Alberta gas is being used in the
province to serve growing demand largely in the production of tar sands oil. The expected decline in
supplies and significant pipeline capacity used to transport Alberta gas to the Eastern U.S. markets kept
Alberta prices strong as compared to Rockies supplies. However, Canadian producers are beginning to
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find and produce its vast regions of unrecovered coal seam and shale formations reversing a trend of
declining production.
Because Alberta gas supplies typically flowed to the eastern U.S. and California where price levels were
generally higher meaning that Alberta supplies were historically priced at a premium to Rockies supplies.
However, the recent shale gas production increase in the U.S. mid-continent has turned historical price
relationships upside down. As more U.S. production reduces the eastward flow of Alberta gas, more of it
competes to flow into the western U.S. forcing Alberta producers to seek additional U.S. export markets.
Thus Alberta supplies are now very competitive, or even lower that Rockies supply as can seen in Exhibit
No. 4, Charts 4 - 6.
Some of the more recent reserve forecasts predict that provincial supplies will 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 should exploration and production ever commence in those basins.
Because of the lower prices levels in current natural gas forecasts, these supplies are not expected to be
available for at least ten-to-twenty years.
Intermountain will continue to utilize a significant amount of Alberta supplies in its portfolio. The Stanfield
interconnect between NWP and GTN offers operational reliability and flexibility over other receipts points
both north and south. Where these supplies once amounted to a trickle in the Company's portfolio,
today's purchases amount to over 50 percent of the company's annual purchases.
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 which has resulted in higher prices. 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 deliverability 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.
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
regional 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 largely eliminated the price advantage that Pacific Northwest markets
have enjoyed. This is not to say that Rockies supplies will be less available to Intermountain but that this
region must now compete, more than ever, with markets paying higher prices which will likely cause an
increase in the cost of future Rockies supplies.
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One remaining capacity constraint is found on the NWP system near Kemmerer, Wyoming (just 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. The good news is that Alberta supplies should continue to be plentiful so long-term the dynamics
between Rockies and Alberta supplies should ensure that they continue remain somewhat price
competitive with each other.
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. While some LNG is currently being imported, the amount as compared to
total U.S. demand is very small.
The 2010 IPR included some discussion and assumption that LNG imports would eventually boost U.S.
natural gas supplies. But the growth in North American natural gas supplies has essentially ended any
new LNG import facilities. Because LNG is traded on the global market, where prices are typically tied to
oil, U.S. produced LNG is very competitive. In fact, several proposed LNG ports have recently proposed
to export LNG to international markets in Asia.
LNG is also becoming more in the discussion relating to displacing boiler and remote oil applications.
Intermountain believes that common sense points towards finding ways to utilize as much LNG as
possible in the U.S. rather than exporting it to other countries. LNG is a practical alternative as a providing
peaking supply, transportation fuel, and can supplement baseload supplies in many remote applications.
LNG is domestic, clean and competitively priced and using it here could displace a huge amount of
imported oil. There are other political advantages that will not be addressed in this document.
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 facilities with the capability to receive any such delivery do currently exist. Cost estimates
to build such capacity begins in the 30 billions 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 facilities would take, by most estimates, up to a decade. In fact, many long term forecasts
predict that these supplies will not be delivered into the North American market any sooner than 2025
2030 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. might be even further out on
the horizon.
TYPES OF SUPPLY
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.
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Intermountain builds its supply portfolio 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 utility 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 utilizes has
allowed for more flexibility in the structure of the portfolio. The historical heavy reliance on mostly longer-
term contracts for the majority of the portfolio has lessened as the Company found that it can shift more of
its supplies to shorter termed spot or index contracts. Doing so provides a better ability 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
portfolio.
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 any time 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.
Intermountain frequently purchases firm spot supplies for a given month and as a rule, targets those
suppliers with reputation for reliability. 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.
The Company does not currently utilize NYMEX based products to "hedge" forward prices but has found
many suppliers that will fix future purchase prices. Doing so provides the same price protection without
the credit issues that come with financial instruments. A certain level of fixed price contracts allows
Intermountain participate in the competitive market while avoiding all of the price volatility (Exhibit No. 4,
Chart 3 shows historical monthly index prices at the main pricing points Intermountain utilizes.) While the
Company does not utilize a fully mechanistic approach, its Gas Supply Committee meets frequently to
discuss all gas portfolio issues, including fixing prices, 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, 2012 market
close. After evaluation, it was determined that although the forecasts were not perfectly identical (as
would be expected), 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 its higher or lower price scenarios. 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
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 Demand 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 daily gas
supplies and maximum pipeline capacity would be enormously expensive as the vast majority of those
resources would be utilized, at best, only a few days each year. So the ability to store natural gas during
periods of non-peak demand for use during peak periods is a cost efficient way to fill the gap between
static levels of supply and capacity vs. the non-linear demand curve.
Intermountain utilizes storage capacity in four different facilities 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) facility located near Plymouth, WA. Intermountain also leases
capacity from Questar Pipeline's Clay Basin underground storage field and also operates its own LNG
facility located in Nampa, ID (See Exhibit No. 4, Map 3 for facility locations).
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 extreme 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 in
a cost effective manner.
Liquefied Storage
Liquefied storage facilities make use of a process that super cools and liquefies gaseous methane under
pressure until it reaches approximately minus 260°F. 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 will only bum when vaporized to a
5-15% concentration with air. Because of the characteristics of liquid, its natural propensity to boil-off and
the enormous amount of energy stored, LNG is normally stored in man-made steel tanks.
Liquefying natural gas is, relatively-speaking, a time-consuming process, the compression and storage
equipment is costly and liquefaction requires large amounts of added energy. It typically requires as much
as one unit of natural gas burned as fuel for every three to four units liquefied. Also, a full liquefaction
cycle may take 5 - 6 months to complete. Because of the high cost and length of time involved filling a
typical LNG facility, it has typically been "cycled" only once per year and is reserved for peaking
purposes. This makes the unit cost somewhat expensive when compared to other options.
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Vaporization, or the process of changing the liquid back into the gaseous state, on the other hand, is a
very efficient process. Under typical atmospheric and temperature conditions, the natural state of
methane is gaseous and lighter than air as opposed to the dense state in its liquid form. Consequently,
vaporization requires little energy and can happen very quickly. Vaporization of LNG is usually
accomplished by utilizing pressure differentials by opening and closing 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 utilized by Intermountain requires the use of year-round transportation
capacity for delivery withdrawals to Intermountain's customers. The Plymouth facility 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 will serve as a needle peak supply.
Recent new market developments provide new potential opportunities to utilize LNG storage on a year-
round basis without jeopardizing peak vaporization. Intermountain is assessing these opportunities to
determine if it can more fully utilize the asset and provide more cost recovery for its utility customers.
Underground Storage
This type of facility is typically found in naturally occurring underground reservoirs or aquifers (e.g.
depleted gas formations, salt domes, etc.) or sometimes in man-made caverns or mine shafts. These
facilities typically require less hardware compared to LNG projects and are usually less expensive to build
and operate than liquefaction storage facilities. In addition, commodity costs of injections and withdrawals
are usually minimal by comparison. The lower costs allow for the more frequent cycling of inventory and
in fact, many such projects are utilized to arbitrage variations in market prices.
Another material difference is the maximum level of injection and withdrawal. Because underground
storage involves far less compression as compared to LNG, maximum daily injection levels are much
higher 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. filling the winter "hump" in the LDC) or daily load balancing and therefore Intermountain
normally uses underground storage before liquid storage is withdrawn.
Intermountain's contracts with two pipelines for underground storage: Questar Pipeline's ("Questar") for
capacity at its Clay Basin facility in Northeastern Utah and Northwest for capacity at its Jackson Prairie
facility. Clay Basin provides the Company with the largest amount of seasonal storage and daily
withdrawal. However, since Clay Basin is not bundled with redelivery capacity, Intermountain must use
its year-round capacity when these volumes are withdrawn. For this reason, the Company normally
"baseloads" Clay Basin withdrawals during the November-March winter period.
Just like Northwest's Plymouth LS facility, Northwest's JP storage is bundled with redelivery capacity and
so Intermountain typically layers JP withdrawals between Clay Basin and its LNG withdrawals. The IRP
uses Clay Basin as a winter baseload supply and JP is used as the first "layer" of peak supply. The Table
below outlines the Company's storage resources for this IRP.
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Table I
Storage Statistics
Seasonal Daily Withdrawal Daily Injection Redelivery
% of 2013
Facility Capacity Max Vol Peak Max Vol 1 # of Days Capacity
Nampa 580,000 60,000 17% 3,500 166 None
Plymouth 1.096.235 113.200 31% 5,660 200 TF-2
Subtotal Liquid 1,676.235 173200 48% 9,160
Jackson Prairie 1,099,099 30,337 8% 15,000 73 TF-2
Clay Basin 8.413,500 70.109 53,933 156 TF-1
Subtotal Undgrnd 9,512,599 100.446 68.930
Grand Total 11.888.834 273646 7.6% 78.093 -
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.
All four storage facilities require the use of Intermountain's every-day, year-round capacity for injection or
liquefaction. Because injections usually occur during the summer months, use of year-round capacity for
injections 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 facilities utilized offers the company and its customers a level of
efficiency, economics and security not otherwise achievable. Geographic diversity provides security
should pipeline capacity become constrained in one particular area. The lower commodity costs and
flexibility of underground storage allows the company flexibility to determine its best use from other supply
alternatives such as winter baseload or peak protection gas, price arbitrage or system balancing. The
Company is also investigating other uses for its LNG faculties.
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 will 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.
Intermountain holds firm capacity on four different pipeline systems including Williams Northwest Pipeline
("Northwest" or "NWP"). Northwest the only interstate pipeline with interconnects to lntermountain's
distribution system meaning that Intermountain physically receives all gas supply to its distribution system
via "Citygate" taps with Northwest. Table I below summarizes the Company's year-round capacity on
Northwest (TF-1) and its storage specific redelivery capacity. Between the amount of capacity
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Intermountain holds on the "Upstream" pipelines (GTN, Foothills, and Nova) and firm-purchase contracts
at Stanfield, it controls enough capacity to deliver a volume of gas commensurate with the Company's
Stanfield takeaway capacity on Northwest.
Table 2
Northwest Pipeline Transport Capacity
Delivery Quantity 2013 2014 2015 2016 2017
TF-1 Capacity-
Sumas 17,291 17,291 17,291 17,291 17,291
Stanfield 169,520 169,520 169,520 169,520 169,520
Rockies 73,243 70,328 70,328 70,328 70,328
Citygate 18.056 18.056 8,056
Total TF-1 278,110 275,195 265,195 272,824 269,959
Storage (TF-2) 143,537 143.537 143,537 143,537 143,537
Max. Citygate Delivery 42164 418.732 408.732 400,676 400.676
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 I-S 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 capabilities, 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 with less regional differentials.
So today Intermountain is in an increasingly mega-regional marketplace where market conditions across
the continent - including pipeline capacities - can, and often does, affect regional supply availability 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
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prices to obtain gas supplies and 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.
Capacity Release
Capacity release was implemented by FERC to allow markets to more efficiently utilize 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 annualized use
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 willing to pay for new infrastructure. But a fuller pipeline can also
mean existing shippers find less operational flexibility.
Intermountain has and continues to be active in the capacity release market. Intermountain has obtained
significant amounts 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
utilized 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 decreased.
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 will increase
capacity in southern BC (Southern Crossing). The
other pipeline, Ruby Pipeline, will connect
Rockies supplies from the Opal, Wyoming area
with west coast markets through its terminal point
near Malin, Oregon where GTN interconnects
with the PG&E in northern California.
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 area), 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 the cost of
doing so is presently not economic.
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 Utilities Commission ("IPUC") provides oversight
and oversees all aspects of natural gas service to Intermountain's customers. Under tariffs approved by
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the IPUC, Intermountain provides sales and transport-only services to over 315,000 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 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
distribution system-only gas under a similar interruptible T-3 tariff.
SUPPLY RESOURCES SUMMARY
Because of the dynamic environment in which it operates, the Company will 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 portfolio 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 portfolio 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 culminates with the optimization model that helps to
ensure that the Company's strategies to meet its traditional gas supply goals are based on sound, real-
world, economic principles.
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NON-TRADITIONAL SUPPLY RESOURCES
Non-traditional supply resources can replace, enhance or help supplement the traditional supply-side
resources during peak demand conditions. Non-traditional resources include two general types:
alternative energy supplies not received from an interstate pipeline supplier, producer or interstate
storage operator and various methods used to increase capacity within Intermountain's distribution
system that enhance the ability to flow gas during periods of peak demand. Five (5) non-traditional
supply resources and three (3) capacity upgrade options were considered in this IRP and are as follows:
Non-Traditional Supply Resources
1.Fuel Oil/Diesel
2.Coal
3.Wood Chips
4.Propane
5.Satellite/Portable LNG Facilities
Capacity Upgrades
1.Pipeline Loop
2.Pipeline Uprate
3.Compressor Station
NON-TRADITIONAL RESOURCES
While a large volume industrial customers' load profile is relatively flat compared to the core market, the
industrials are still 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, diesel and wood chips, an industrial
customer can lower their natural gas requirement during peak load periods while continuing to receive the
energy required for their specific process. Although these alternative resources and related equipment
have the ability to operate any time during the year, most are ideally suited to run during peak demand
due to cost and availability issues.
Generally only the industrial market has the ability to use any of the aforementioned alternate fuel in large
enough volumes to make any material difference in system demand. Historically, only industrial
customers located along the Idaho Falls Lateral (IFL) have had the ability 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 availability. The incremental cost of these kinds
of arrangements, if any, is difficult to assess.
The remaining non-traditional resource, Satellite/Portable liquid natural gas (LNG) facility, while not
technically a form of demand side management, has the ability to provide additional natural gas supply at
favorable locations within a potentially constrained distribution system. Satellite/portable LNG can
therefore supplant the normal capacity upgrades performed on a distribution system by creating a new,
portable supply point to maximize capacity possibilities. However, Satellite/Portable LNG is normally
intended to be a short term, peak resource rather than an everyday supply.
Fuel Oil/Diesel
There are three large volume industrial customers along the IFL that currently have the potential to use
fuel oil as a natural gas supplement. The plants are able to switch their boilers over to bum oil and
decrease a portion of their gas usage, but only one plant has the ability to run in full operation with oil
alone. Burning fuel oil in lieu of natural gas requires 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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Out of the three industrial customers that historically had the necessary equipment to burn fuel oil, only
one currently has the ability to burn fuel oil. The other two customers can't either due to lack of permit
application or choosing to no longer purchase and store fuel oil at their facilities. The estimated cost of oil
is between $2.80 - $3.80 per gallon depending on fuel grade and classification, time of purchase and
quantity of purchase. The conversion cost to natural gas is roughly $1.90 to $2.90 per therm.
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 additional equipment installed to transport the large quantities of coal within their
facility. Regulations and permitting requirements can also be a challenge. Intermountain currently has a
few industrial customers throughout the system that support coal backup systems, but only one industrial
customer who has firm gas demand that is capable of and willing to burn coal. This customer is located
on the IFL, supplements their winter gas usage with coal on a regular basis and has the ability to run
almost entirely on coal if requested. The maximum offset in gas supply is 1,800 therms of natural gas
each day.
The cost of coal in the northwest is approximately $75 per ton, including transportation and 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 at roughly $0.35 - $0.42 plus 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 facilities for the wood chips. The wood is supplied from various tree clearing and
wood mill operations that produce chips within regulatory specifications to be used as fuel. The chips are
then transported by truck to the location where the customer will typically store a two to three 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 utilize any more wood
fuel than they are currently using.
The cost of wood is continually changing based on transportation, availability, location and the type of
wood processing plant that is providing the chips. Wood has a typical value of 4,500 BTU per pound,
which equates to twenty-two pounds of wood being burned to produce one therm of natural gas. An
approximate cost of purchasing wood chips in the northwest is estimated at $75.00 - $100.00 per ton
which converts to $0.82 - $1.10 per delivered therm.
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,
utilizing 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 levels. Currently there are no industrial customers on the system that have the ability
to use propane as a feasible alternative to natural gas; although, at least one customer is reviewing the
possibility and planning to install propane redundancy within the next few years.
Capital costs for propane facilities can become relatively high due to storage requirements. 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
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accommodate -a peak day delivery load for approximately seven days. The average cost of propane
ranges from $2.10 - $2.20 per gallon, which is a natural gas equivalent to $2.28 - 2.39 per therm.
[NOTE: One gallon of propane is approximately 92,000 BTU]. Fixed O&M costs are approximately
$50,000 - $100,000 per year.
Satellite/Portable LNG Equipment
Satellite/Portable LNG equipment allows natural gas to be transported in tanker trucks in a cooled liquid
form; meaning that larger Btu quantities can be delivered to specific high demand locations throughout
the distribution system. Liquefied natural gas has tremendous withdrawal capability due to the natural
gas being in a more dense state of matter. Portable vaporizer equipment has the ability to convert LNG
from its -260°F liquid state to its gaseous form by raising the temperature to a typical temperature of 50°F
- 70°F where it can be delivered into the distribution system. This portable equipment is available to lease
or purchase from various companies and can be used for peak shaving at industrial plants or within a
distribution system. Regulatory and environmental approvals are minimal compared to permanent LNG
production plants and are dependent upon the specific location where the portable LNG equipment is
placed. The available delivery pressure from LNG equipment ranges from 150 psig to 650 psig with a
typical flow capability of approximately 2,000 - 8,000 therms per hour.
Intermountain currently operates a satellite LNG facility on the IFL that includes a permanent storage
tank, a portable vaporization unit and an onsite control building. It is located on the northern end of the
IFL near Rexburg, Idaho and is designed to protect against peak demand pressure loss on the northern
end of the lateral.
The onsite tank can hold approximately 55,000 gallons of LNG (the equivalent of about 45,000 therms)
that can quickly be injected into the IFL. The ability to store LNG onsite helps to mitigate the risk
associated with supply failure during a critical weather period as Intermountain does not have to rely
solely on truck deliveries should that region experience fast-moving design weather. Additionally, now
that Intermountain has installed a truck loading station at its Nampa facility, the company no longer has to
rely on third-party LNG suppliers which further minimizes the risks related to cost and availability.
The portable vaporizer unit has the capability to vaporize LNG from the onsite storage tank and directly
from mobile tanker trailer units. The unit can inject vaporized LNG into the IFL system at high pressure.
Should longer duration cold spells occur, the flexibility to directly connect the portable vaporizer with
trailers provides for continued receipt of LNG supply even if the storage tank is emptied.
The cost of the portable LNG equipment is approximately $1 - $2.5 million with additional cost to either
lease or purchase property to place the equipment and the cost of the optional permanent LNG facility.
The fixed cost to lease the portable equipment is approximately $200,000 - $300,000 per month plus the
cost of LNG.
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2013-2017 Integrated Resource Plan
DISTRIBUTION SYSTEM MODELING
Gas pipeline systems utilize pressure differentials to move gas from one point to another. Equal
pressures on both ends of a closed pipeline system indicate that gas flow does not exist. When gas is
removed from some point on a system during the operation of natural gas equipment the pressure in the
system at that point is then lower than the pressure upstream in the system. This pressure differential
causes gas to move from the higher pressure point to the point of gas removal in an attempt to equalize
the pressure throughout the distribution system. The same principle keeps gas moving from interstate
pipelines to the LDC distribution systems. 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 designed appropriately
to create a feasible and practical pressure differential when gas consumption occurs on the system. The
goal is to maintain a system design where load demands do not exceed the system capacity; which is
defined by the minimum pressure allowed at a determined point or points along the distribution system
(generally the farthest point in the system away from a pressure source).
The determination of flow dynamics through a pipeline 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 within 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 "pipeline system modeling." Ultimately, gas flow dynamics on any given pipeline lateral
and/or distribution system can be ascertained for any set of known gas loading. The maximum system
capacity is determined through the same methodology using estimated cold weather events and
calculated customer gas demands.
In order to evaluate intricate pipeline structures a system model is created to assist an engineer in
determining the flow capacity and dynamics of those pipeline structures. For example, before a large
usage customer is incorporated into an existing distribution system the engineer must evaluate the
existing system and then determine whether or not there is adequate capacity to maintain that potential
new customer along with the existing customers, or if a capacity enhancement is required to serve the
new customer. Modeling is also important when planning new distribution systems. The correct diameter
of pipe must be designed to meet the requirements of current customers and reasonably anticipated
future customer growth.
MODELING METHODOLOGY
Intermountain utilizes a gas network modeling and analysis software program called SynerGEE Gas,
distributed and supported by GL Noble Denton, to model all distribution systems and pipeline flow
scenarios. The software program was chosen because it is reliable, versatile, continually improving and
able to simultaneously analyze very large and diverse pipeline networks. Within the software program
individual models have been created for each of Intermountain's various distribution systems including
high pressure laterals, intermediate pressure systems, distribution system networks and branched service
connections.
Each system's model is constructed as a group of nodes and facilities. Intermountain defines a node as a
point where gas either enters or leaves the system, a beginning and/or ending location of pipe and/or
non-pipe components, a change in pipe diameter or an interconnection with another pipe. A facility is
defined in 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 facilities, a medium town typically consists of 500 - 1,500 nodes and 1,200 facilities, and a large city
or area typically consists of 5,000 or more nodes and 5,000 or more facilities. The Boise/Meridian
distribution model is the Company's largest and involves approximately 24,000 nodes and 26,000
facilities.
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SynerGEE can analyze a pipeline system at a single point in time or the model can be specifically
designed to simulate the flow of gas over a specified period of time; which more closely simulates real life
operation. While modeling over time an engineer can input and/or manipulate the gas loads, time of gas
usage, valve operation and compressor simulations within a model, and by incorporating the forecasted
loads within this Integrated Resource Plan Intermountain 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 feasibility, timeline, cost and increased capacity for each theoretical
system enhancement is determined and then placed into a comparison analysis and used within the IRP
model.
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AVAILABLE AND POTENTIAL SYSTEM CAPACITY
ENHANCEMENTS
Throughout previous sections of the IRP it has been shown how projected growth throughout
Intermountain's distribution systems is monitored to identify future potential 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, potential deficits are defined with respect
to timing and magnitude. Where any such deficit occurs available system capacity enhancements are
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,
Canyon County Area, Idaho Falls Lateral, and Sun Valley Lateral segments. Each of these areas is
unique in its pipeline characteristics, and the optimization of each requires different enhancement
solutions.
STATE STREET LATERAL SEGMENT
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 back fed with another pipe system from the south. Much of the pipeline is closely
surrounded by residential and commercial structures that create 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 retest; where the additional pressure at this
location is obtainable and the Company has a chance to maximize the potential of its existing facilities
before investing in new. The retest can be performed in phases over multiple years that provide
increased capacity as actual growth is experienced, and the phasing will minimize the length of pipe that
must be taken out of service each time. The State Street enhancement is not required within the five year
projection of this IRP but it is continually being monitored and planned for within the company.
CANYON COUNTY SEGMENT
The Canyon County area has multiple, high pressure pipelines of various diameters and pressures
spread throughout the system but there exists a single, undersized, bottleneck line which stands out as
the weakest point in the system. The selected enhancement for this situation is a pipeline loop that will
circumvent the current bottleneck restriction and prepare the system to utilize higher pressures in the
future. The loop is planned to be 7.8 miles long and the current constructed design utilizes 8" steel pipe.
The loop line, named the 8" Orchard-Farmway Loop, has a planned in-service date of Fall 2014 and will
increase the system capacity past the five year customer growth projection.
IDAHO FALLS LATERAL SEGMENT
The IFL began as a 52 mile, 10" pipeline that originated south of Pocatello and ended at the city of Idaho
Falls. The IFL was later extended with 8" pipe for an additional 52 miles to serve customers farther to the
north, notably the cities of Rigby, Rexburg and St. Anthony. As demand has continually increased along
the IFL, Intermountain has been completing capacity enhancements for the past 20 years; including,
compression (now retired), a satellite LNG facility, 40 miles of 12" pipeline loop, and 18 miles of 16"
pipeline loop.
The 2010 IRP indicated a need for additional capacity on the IFL. So, in 2011 Intermountain moved
forward with a plan to design and install an additional section of 16" pipeline around the city of Idaho
Falls, named the 16" Idaho Falls Lateral Phase V Project. The project was completed in the winter of
2012 and provides the following benefits:
1. Completes the looping of the entire section of the original 10" IFL.
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2.Reduces the maximum allowable operating pressure on a parallel transmission pipeline section of
the original IFL.
3.Removes multiple High Consequence Areas from the Integrity Management Plan.
4.Reduces the cost of any inline inspection and pigging that may be required on transmission
pipelines in the future.
The installation of Phase V will impact the 2012 IRP by delaying the installation of a second LNG storage
tank at the Rexburg LNG Facility that was planned for a 2012 installation, and Phase V will increase the
permanent IFL capacity. The IFL capacity gained will allow Intermountain to provide additional, year
round supply that can be utilized for growth by current customers and well as future potential customers.
SUN VALLEY LATERAL
The SVL is a 70 mile long, 8" high pressure pipeline that has almost its entire demand at the far end of
the lateral away from the gas source. The 2010 IRP showed the need for additional capacity on the SVL.
However, finding land in close proximity to this customer load center is either very expensive or simply
unobtainable. This situation prompted Intermountain to install a compressor station towards the south
end of the lateral and boost pressure north towards the demand. The compressor was installed in the
winter of 2010/2011 and increased lateral capacity from 175,000 therms per day to 204,000 therms per
day. With this compressor in operation the SVL is currently not a constraint point in lntermountain's five
year forecast horizon, but remains in the IRP because of the unique characteristics of the system.
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THE EFFICIENT AND DIRECT USE OF NATURAL GAS
NATURAL GAS AND OUR NATIONAL ENERGY PICTURE
According to the American Gas Association, in the United States natural gas currently meets nearly 25%
of the nation's energy needs, providing energy to more than 65 million American homes. The residential
market comprises 23% 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. Roughly
193,000 industrial and manufacturing sector customers use natural gas in their processes consuming
32% of the U.S. annual total. And in another fast-rising sector, 5,500 electric-power-generating units
produce 23% of total U.S. electricity, consuming the remaining 30% of annual U.S. demand.
The simple reason for the widespread use of this energy source is that 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, 98.5% of the natural gas used in the United States comes from North America, where
supplies are abundant. The 2.1-million-mile underground natural gas delivery system has an outstanding
safety record, and is reliably capable of delivering natural gas, regardless of the weather.
Thus, for all the right reasons, the demand for natural gas has risen. In the past, its price had risen
markedly with the increased demand. But now, due to significant new domestic natural gas discoveries in
North America (and in part due to our still-soft economy), the wellhead price of natural gas has dropped to
levels not seen since 2002. Furthermore, the previous price-volatility exhibited over the last 10 years has
calmed considerably.
Natural gas is now even more plentiful in North America, with an estimated 100 year 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 more years.
Even with this plentiful supply, and lower, more stable prices, it remains vital that all natural gas
customers use the energy as wisely and as efficiently as possible.
NATURAL GAS EQUIPMENT EFFICIENCY
Technology has given us many new and more efficient ways to meet our energy needs without sacrificing
the environment. In 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 newer, more efficient units. Thus, the entire natural gas user base grows more efficient
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. As with the replacement of older equipment mentioned above, older housing and
commercial units are being upgraded to higher efficiency standards. Annual residential gas usage per
customer dropped by 25% between 1996 and 2010. Overall, the average U.S. residential customer uses
32% less natural gas than it did in 1980, thanks largely to the aforementioned efficiency improvements.
Average annual Intermountain residential customer gas consumption has dropped by 13% since 2000.
Natural gas equipment efficiency makes economic sense in today's new energy era, and IGC will
continue to encourage new residential and commercial technologies, as they become available.
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NATURAL GAS CONSERVATION CUSTOMER EDUCATION
Website
On Intermountain's website, www.intgas.com , residential and small commercial customers can obtain
detailed information regarding energy conservation at their home or business. Large-volume/industrial
customers have their own website where they can obtain real-time gas consumption information.
Also at the website, customers can view the Energy Conservation Brochure, which was also mailed to all
Intermountain's core-market customers in January 2012.
In addition to bill paying and other services, IGC customers can also access their individual billing and
gas consumption history on the website. Customers can enroll online or by phone. The process is easy,
and access is immediate. Intermountain's customer communications, mass-media advertising, website,
and marketing information all encourage customers to consider high-efficiency equipment when making
their equipment purchase or upgrade decisions.
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. Plant efficiency and optimizing
production volumes using the least amount of energy is a very high priority for the owners, operators, and
managers of these large volume plants. The information on this site is gathered through the company's
SCADA system, and is transferred to the web-based site. The site is accessible via the internet 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. This "real-time" information has helped many of the plants with
their energy conservation and efficiency needs.
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2013-2017 Integrated Resource Plan
Lr
Viewing Consumption
*Note: Usage information is shown in Decatherms
There are several tools available to review, evaluate, and analyze natural gas consumption at their
specific facility. The meter reads are taken hourly, and sent via radio communication to Intermountain's
Gas Control Center. Once this information is in the 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.
Intermountain 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 fulfill their needs.
IGC's customer contact and marketing personnel are equipped to assist current and potential customers
with evaluating the advantages of installing high-efficiency gas equipment where possible. Additionally,
Intermountain has offered to consult and help direct leak detection and corrosion control efforts on the
natural gas piping systems within the customers' facilities.
Education
Intermountain personnel participate in public safety training and energy conservation seminars around the
state. Intermountain has a long history of promoting the efficient use of natural gas by our customers.
Over the years, IGC has offered rebates and incentives for the installation of energy saving devices such
as pilotless furnace ignition systems, furnace flue dampers, and still to this day, a high-efficiency (90%)
furnace conversion rebate.
IGC is a member of the Energy Solutions Center Renewable Energy Workgroup. Intermountain 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
facilities. Intermountain is currently working with the Community Action Partnership Association of Idaho
(CAPAI) to provide energy consumption data for those residential recipients of the Sustainable Energy
Resources for Consumers (SERC) grants in our service territory.
In the fall of 2007, Intermountain became an ENERGY STAR Utility Partner. Through this partnership,
we promote energy efficiency 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 dwellings.
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Intermountain is an active voice in Idaho's legislative process as the lawmakers consider new, higher-
efficiency building and energy codes.
RESEARCH
Intermountain has provided financial assistance to the University of Idaho Integrated Design Lab to
further that entity's energy efficiency research and training.
The Gas Technology Institute ("GTI") continues to perform important ongoing research and development
work in the gas equipment arena, from residential to large industrial. Gil is our nation's leader in ongoing
natural gas R&D, as well as the deployment and commercialization of new gas efficiency technologies.
Intermountain has participated in GTI R&D projects, and will continue that collaboration as the
opportunities arise. In the spring of 2010, GTI and Intermountain conducted a natural gas usage and
feasibility 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 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 still being studied. The various applications had financial recovery just in gas and water
savings ranging from 1.55 to 7 years.
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 end-use point for space heat, water heating, and other
applications, as opposed to using natural gas to generate electricity to be transmitted to the end-use point
and then employed for space or water heating.
As electric generating capacity becomes more constrained in the Pacific Northwest, additional generating
capacity will primarily be natural gas fired. While development of additional hydro or coal-fired generating
facilities may be nearly impossible, those already in place will continue to operate at generally full
capacity for many years to come. Direct use will mitigate the need for future generating capacity. If more
homes and businesses use natural gas for heating and commercial applications, then the need for
additional generating resources will be forestalled. 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.
This more efficient, direct use obviously translates into a much lower carbon footprint. Two examples are
coal fired electricity versus natural gas and natural fired electric plants versus direct use. First, let's look
at coal-fired electricity, which makes up a sizeable portion of our region's power supply.
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 million btu's per ton (9,000
btu's per pound). When burned, this ton of coal produces over 3,700 pounds of CO2 into the atmosphere
(1.85 lbs of CO2 per pound of coal burned). At the facility's 40% heat rate, for each kilowatt-hour (3,413
btu'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 lbs of CO2. Delivering 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 CO2 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.
Now, let's consider natural gas powered electrical generation plants. Natural gas fired combustion
turbines like Langley Gulch, 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-efficiency 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 directly to the
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end user emits roughly 12 lbs of CO2 into the atmosphere. The equivalent amount of electricity, 100,000
btu's, or just under 30 kilowatt hours emits roughly 24 lbs of CO2, 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.
So, from a resource and environmental basis, direct use makes the most sense. More energy is
delivered using the same amount of natural gas, resulting in lower cost and lower CO2 emissions spread
out over a far wider airshed. This direct, and therefore, more-efficient natural gas usage will serve to
keep natural gas prices, as well as electricity prices, lower in the future. Our success in marketing to
Idaho's residential new construction market, where we have a 95% penetration rate along our service
mains, is a prime example of the direct use of natural gas, where possible.
To illustrate the significant role that IGC plays in southern Idaho's total energy picture, IGC has over
285,000 residential customers. The average annual therm usage of an IGC space-heating-only customer
is 565 therms. That equates to a total residential therm usage of approximately 161,000,000 therms in a
year. If the total was used at the Federal efficiency minimum of 78%, then (161,000,000 X .78 =
125,580,000 therms X 100,000 btu's/therm) or 12,558,000,000,000 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
(12,558,000,000,000 / 3,412) or 3,680,539,273 kilowatt-hours in a year to heat their homes. This is the
same as 3,680,539 megawatt hours of power saved, year in, year out. According to their 2010 Annual
Report found on their website, Idaho Power's total annual residential megawatt hour sales for 2010 were
4,967,000. If the aforementioned 285,000 IGC residential customers were using electric space heat
instead of natural gas, Idaho Power's total residential sendout would rise to 8,647,539 mWh, a 74%
increase, requiring considerable additional generation and transmission facilities.
In peak terms, if these 285,000 Intermountain 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 2,375 megawatts. Again, according to their website, Idaho Power recently
experienced a February 2011 winter peak load of 2,261 megawatts. Without the direct use of natural gas
to heat these 285,000 homes, Idaho Power's winter peak load could reach 4,653 megawatts, a 105%
increase! The additional 2,375 megawatt peak load would be the equivalent of nearly eight 300
megawatt natural gas-fired electric generating facilities, like Langley Gulch, all running at full throttle. This
would probably also require a substantial increase in transmission facilities to handle this peak load, since
it would be well above the Idaho Power July 2011 Summer peak of 2,973 megawatts.
In terms of recently-shed electric load, just since 1991, Intermountain 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 356,000 megawatt hours of residential sendout per year. In
winter peak terms, using the 1/3 operating simultaneously" example in the paragraph above, 233
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 water heating were included, the annual sendout
figures would rise by at least 25%.
In terms of summer energy consumption, Intermountain's residential water heaters also provide
significant relief to the ever-growing hot weather electric demand. IGC has over 220,000 RS-2 (space
and water heat) customers. If, instead these were 220,000 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 $1,901,000 in September to $4,435,000 for July. But the summer
water heating load curtailment and shifting provided by Intermountain's water heater customers has come
at no cost to electric utilities 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
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the name suggests, LUAF is the difference between volumes of natural gas delivered to Intermountain's
distribution system and volumes of natural gas billed to Intermountain's customers. Intermountain 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.
Billing and meter audits are important processes that Intermountain has established to address LUAF.
Billing audits to identify Low Usage and Zero Usage are performed with each billing cycle. Low Usage
Reports are used to compare billed consumption against that same customer's historical usage patterns.
If the current month's billed 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 billed consumption for a given meter size. There should arguably
be a correlation between the customer's billed 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 billed
consumption.
Intermountain also works to ensure billing accuracy of newly installed meters. A Service Tech (different
from the Service Tech that installed the meter) performs a Meter Audit on meter classes with drive rates
or billing pressures that don't have a one-foot drive rate and four ounce billing pressure, respectively.
These audits are performed to ensure that the correct drive rate and billing pressure are programmed for
the meter and billing system to avoid billing errors. Any corrections are made prior to the first bill going
out.
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 rotations are also an important tool in keeping LUAF levels low. Intermountain conducts regular
samples of its meters to test for accuracy. A rotation plan is developed by applying the "ANSI/ASQ Z1.9
- 2003 Sampling Procedures and Tables for Inspection by Variables for Percent Nonconforming"
standard for sampling to the eligible families 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 a benchmark proving piece of
equipment (Sonic Nozzle Auto Prover - SNAP). The results of 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
sampling would take place and any necessary follow up remedial measures would be taken.
In addition to these regular meter audits, Intermountain also identifies the potential for incorrectly sized
and/or type of meter in use by our larger industrial customers. 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 facilitate a monthly comparison to the billed
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volumes as determined by the customer's meter. If a discrepancy exists between the two measured
volumes, remedial action is taken.
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
Ever-increasing and more pervasive energy standards and practices will continue to improve the energy
efficiency of Intermountain Gas Company's customers. Intermountain will continue in its active role
promoting the wise and efficient use of natural gas and in carefully monitoring LUAF levels. The wise,
direct use of natural gas in the coming years will help keep overall energy costs low in southern Idaho,
help protect the environment, and ensure ample, lower-cost electricity for its many other valuable uses.
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DEMAND-SIDE MANAGEMENT
The analysis, selection, and potential deployment of natural gas efficiency and conservation measures is
known as Demand-Side Management, or DSM. The goal of Intermountain's DSM analysis was two-fold:
1) to ascertain whether achievable and economically viable DSM could provide a reliable resource in the
Company's peak-load management, and 2) to facilitate year-round improvements in natural gas usage.
DSM includes behavior modification, building-envelope improvement, and higher-efficiency natural gas
equipment. One particularly important consideration is the comparison of the cost of DSM employed to
reduce the growing demand vs. the cost of building additional infrastructure, purchasing pipeline capacity,
or purchasing the natural gas commodity, to meet the growing demand.
The Total Resource Cost ("TRC") test is a widely-used measure of DSM cost. In that model, the
capitalized annual cost of a DSM measure is divided by the annual therms saved over the expected life of
the measure. The peak therms saved can also be applied to this equation. In either instance, the unit
(per therm) cost of reducing demand growth can be compared to the unit cost (again, per therm) of
building capacity and purchasing supply to meet the additional demand. Again, either from a year-round,
or peak-day perspective.
The Intermountain Gas Company DSM process consisted of three steps:
1.Establish broad DSM objectives
2.Ascertain and address a full spectrum of DSM opportunities
3.Perform an assessment of DSM programs
The objectives of a potential DSM program are to provide customer service, accommodate high efficiency
and off-peak load growth, limit the need for new staffing resources, and continue to provide low cost
energy while focusing solely on the most cost-effective DSM measures.
ADDRESSING A FULL SPECTRUM OF POTENTIAL DSM PROGRAMS
In 2007, Intermountain commissioned a DSM study by Navigant Consulting (Navigant) to assist in the
discovery and evaluation of a full spectrum of DSM opportunities. An important requirement of Navigant's
work was that only established natural gas DSM measures being employed by other gas utilities were to
be catalogued and evaluated. The Company provided Navigant with customer segmentation and
distribution data, service-area market assumptions, and other pertinent data. Navigant's work was very
thorough, and various measures were listed, along with their various costs, market deployment potential,
peak savings, and year-round gas savings. DSM programs listed were also broken down by their market
potential in the distribution system segments, as described elsewhere in this IRP.
The programs listed in Navigant's work included ductwork improvements, appliance efficiency upgrades,
insulation improvements, ventilation upgrades, improved windows, and other building envelope
measures.
For the 2012 IRP analysis, this Navigant study was updated to reflect current market conditions,
efficiency assumptions, and natural gas costs.
ASSESSMENT OF POTENTIAL DSM PROGRAMS
In assessing the potential DSM options, Intermountain chose to first consider programs which would not
duplicate other programs, would not be redundant with regard to codes or other regulations, and would
provide a truly additional energy savings.
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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 utility cost savings that outweigh the additional monthly mortgage payment to
cover their higher cost. Therefore, new-home buyers already have a financial incentive to include
enhanced energy efficiency features in their new home.
Since these new-construction efficiency measures already offer a significant financial incentive,
Intermountain proposes to continue its promotion of high-efficiency new construction in our advertising,
builder association participation, and through our ENERGY STAR Utility Partner activities. This market-
based approach makes the most sense in the new-construction arena. Our advertising promotion of
high-efficiency new homes and ENERGY STAR is ongoing.
In the 2010 IRP, Intermountain proposed the following DSM programs be implemented in calendar year
2011 as a pilot program on the Idaho Falls Lateral. No regulatory filing was undertaken, and the
proposed programs 2, 3, and 4 have not been implemented.
1.Continue the existing $200 rebate for customers converting to natural gas if they purchase a
90%-or-greater efficiency furnace.
2.Begin a new program to provide a $30 rebate if a customer converts to a .64 or greater EF
natural gas water heater from another source.
3.Implement a new program to provide a $200 rebate if an existing customer replaces a below-
90%-efficiency furnace with a 90%-or-greater efficiency natural gas furnace.
4.Implement a new program to provide a $30 rebate if an existing customer replaces an existing
natural gas water heater with a .64 or greater EF gas water heater.
Intermountain's $200 furnace rebate program outlined in (1) above is still available. The total rebates
issued in 2009 were $22,800, $34,000 in 2010 and $35,600 in 2011. This program will continue in its
present form.
Since the 2010 IRP, there have been significant changes in the natural gas market. Starting with our
October 2010 Purchased Gas Adjustment (PGA), Intermountain has lowered its core-market gas prices
three times in a row to the core market customer classes by 8.7%, 9.9%, and 12.1%, respectively.
Furthermore, these reductions followed two preceding PGA price reductions totaling nearly 30% for the
core-market. As a result of this nearly 40% residential price reduction since 2008, the aforementioned
residential DSM programs previously considered for pilot implementation will not provide the cost-benefits
estimated under the significantly higher gas prices assumed in the previous IRP.
Additionally, the U.S Department of Energy has set new rules mandating higher, region-based minimum
efficiency standards for residential water heaters. Currently, U.S. gas water heater efficiency standards
mandate .59 Energy Factor (EF) for 40 gallon units. Beginning April 2015, 40 gallon natural gas water
heaters will be required to have a .62 EF.
The lower natural gas prices, which are expected to remain at these lower levels at least through
Intermountain's next IRP filing, put the proposed DSM programs below the TRC threshold for cost
effectiveness. Further, the new higher Federal efficiency standards indicate that Intermountain's offering
of financial incentives on these significant-use appliances are unnecessary. Such incentives would place
an undue financial burden on the Company's entire customer base, when the law will begin mandating
these higher efficiencies anyway.
Intermountain remains committed to promoting the efficient, direct use of natural gas wherever possible,
and will continue to promote the wise use of all energy.
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RESOURCE OPTIMIZATION
INTRODUCTION
Intermountain's IRP utilizes 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 utilizing a standard
mathematical technique called linear programming.
This summary will first describe the model structure and its assumptions in general. Initial results will then
be discussed.
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 utilized in the Company'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 1MG 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 I and 2 on the following page.
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Figure 1
Graphical System Map
Table I
Demand and Supply Nodes
Area # 1 2 3 4 5 6 7 8 9 10 11
Name Sumas Stanfield North
Green
South
Green
NIT 1MG
Pool
All
Other
Canyon
County
Idaho
Falls
Sun
Valley
State
Street
Table 2
Demand and Supply Nodes and Applicable Transport Arcs
ArA!NndA From Area/Node To
ARC # Name Area # To Area #
I Sumas I 1MG 6
2 Stanfield 2 1MG 6
3 N. Green 3 1MG 6
4 S. Green 4 1MG 6
5 NIT 5 Stanfield 2
6 1MG 6 All Other 7
6 1MG 6 Canyon 8
6 1MG 6 Idaho Falls 9
6 1MG 6 Sun Valley 10
6 1MG 6 State Street 11
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LOAD DEMAND CURVE CHART
As previously discussed, to simplify modeling the Load Demand 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 still
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 LOG looks after the aggregation and averaging is performed. The
optimization model utilizes 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 2011-15 IRP
Sample Design Daily LDC vs. Aggregated LDC (Dth)
500,000
450,000
400,000
350,000 -7. -
200,000 *
150,000
-- -- 100,000
50,000
0
1 16 31 46 61 76 91 106 121 136 151 166 181 196 211 226 241 256 271 286 301 316 331 346 361
Chronological Days
- - Daily

.DC a Aggregated LDC
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 each
day a certain level of firm transport capacity for its firm transporters, 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 two types: supply resources and storage contracts which, from a
modeling standpoint, are utilized in a similar manner. All resources have beginning and ending years of
availability, period of availability, must take usage, period and annual flow capability and a peak day
capability. Supply resources have price/cost information entered in the model over all points on the load
demand curve for the study period. Additionally, information relating to storage resources includes
injection period, injection rate, fuel losses and other storage related parameters are included.
Each resource must be sourced from a specific receipt point or supply area. One advantage of Citygate
supplies and certain of the storage withdrawals is that they do not utilize any of Intermountain's existing
interstate capacity as the resource is either sited within a demand area node or are bundled with their
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2013-2017 Integrated Resource Plan
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 utilizing
available "Upstream" capacity - the available quantity at Stanfield is the limiting factor regardless of
capacity of any singe Upstream pipeline. Each supply utilizes the appropriate transport arc(s).
From a model perspective, the DSM resources are considered a subset of supply resources and fill
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
Transport resources are explicitly associated with arcs in the model which represent the way supplies flow
from specific receipt areas to Intermountain's ultimate receipt pool identified as "1MG" where all supplies
are pooled for ultimate delivery into the Company's various 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 Northwest's Stanfield interconnect (because these pipelines operate in a
serial fashion and have nearly identical flow capabilities, 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 1MG arc and from there flow from 1MG to the
Idaho Falls arc. This ensures that the total supply deliveries cannot exceed total demand including
laterals. Supplies such as the Rexburg LNG are already located on Intermountain distribution system on a
specific demand lateral and therefore do not require interstate pipeline transportation. The system
representation recognizes Northwest's postage stamp pricing and capacity release.
Transport resources have a peak day capability and are assumed to be available year round unless
otherwise noted. Transport resources can have different cost and capabilities assigned to them as well
as different years of availability. For example, different looping options for the Idaho Falls lateral are
available to the model at different periods to facilitate the flexibility of timing decisions.
E1'] I[.i
The selection of a best cost mix of resources, or resource optimization, is based on the cost, availability
and capability of the available resources as compared to the projected loads at each of 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 will exclude resources it
deems too expensive compared to other available alternatives.
The model can treat fixed costs as sunk costs for certain resources already under contract. If a fixed cost
or annual cost is entered for a resource, the model will include that cost for the resource in the selection
process that will influence its inclusion vis-à-vis other available resources. If certain resources are
committed to and the associated fixed cost will be paid 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, will be evaluated using both fixed and variable cost.
The model operates in a PC environment. The various inputs are loaded via an Excel spreadsheet where
they are loaded and utilized 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 calling up the correct constraint
model set. The optimization software 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
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set of macros that writes the output back into the same Excel model which simplifies, and minimizes the
time, to audit and evaluate the model for reasonableness accuracy.
SPECIAL CONSTRAINTS
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.
• LNG storage does not require redelivery transport capacity. Both SGS and LS storage are bundled
with firm delivery capacity; transportation utilization of this capacity matches storage withdrawal from
these facilities.
• All core market and LV-1 sales loads are completely bundled.
• The 1-3, T-4 and T-5 customer transportation requirements utilize only Intermountain's distribution
capacity. Each of the transport classed total firm CD is input as a no-cost, supply delivered at 1MG.
• Traditional resources destined for a specific lateral node (e.g. IFL) must be first transported to the
1MG pool and then from 1MG 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 otherwise fully utilized.
MODEL RESULTS
The optimization model results for the Design Weather, Base Price and Base Growth scenario for the
years 2013 through 2017 are presented and discussed below. The results of the model are summarized,
for each demand scenario using the tables described below:
• Supply 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, transport and total annual resource 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 I 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 UTILIZATION - 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 will summarize the utilization of each type of supply and
transport resource for the model years I 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 I 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.
Intermountain Gas Company
2013-2017 Integrated Resource Plan
The model selects the best cost portfolio based on relative variable cost pricing. However, it also has
been designed to comply with operational and contractual constraints that exist in the real world (i.e. if the
most inexpensive supply is located as Sumas, the model can only take as much as can be transported
from that point and it will not take inexpensive spot gas until all constraints related to term gas or storage
are fulfilled). 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 selling those volumes into the market at the then prevailing prices
whereas the model only identifies those volumes and cost thereof.
Another important assumption relates to the "Fill" options. Fill resources provide intelligence as to where
and how much of any deficit in any existing resource exists; the model treats them economic commodities
meaning that availability is dynamic up to its maximum capability The model can select available Fill
supply at any node, for any period and in any volume that it needs to help fill capacity constraints. To
ensure that the model provides results that mirror reality, these supplies have been aggregated into peak,
winter, 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.
The storage injection table provides the amount of resources injected into the various storage facilities 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 capability, 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.
Again, the incremental transportation "Fill" contracts are treated as "commodity" resources in that the
model can utilize 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 Fill 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.
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 Fill 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.
0
Intermountain Gas Company
2013- 2017 Integrated Resource Plan
DESIGN BASE CASE - YEAR I (SEE EXHIBIT No. 4, TABLE 5.1)
Supply Resources
The existing supply resources (contracts 2 - 8) have usage rates of 100% for all applicable periods
meaning that these resources are utilized at maximum capacity in all demand periods (the resources with
that are empty reflect resources that were previously utilized in prior IRP's but not for this IRP. The
positions have been left in place with null data for ease of model data loading and auditing and can be
considered placeholders for use in future IRPs.
Resources 36 - 63 represent incremental spot-type volumes that the model may select to fill-in where
loads exceed term volumes and/or storage where applicable. Resources 25, 26 and 29 reflect the
requirements of transport distribution-only customers who provide their own interstate capacity and
commensurate amount of supply at the 1MG 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 2 and 7 are Citygate supplies that are also delivered at the 1MG Pool but these deliveries are
for the Intermountain's sales customers and have the advantage of not using any of the Company's
existing interstate capacity. Resources 31 - 37 are lateral supplies that they model would choose if there
was not enough capacity on the specific to serve forecast loads in any period.
A significant amount of spot-type supply from all supply basins (Resources 42, 50, 51, and 64) is utilized
during periods I - 12. Alberta supplies (50, 51 and 55) are utilized all year long while Sumas (42) supplies
are needed only during periods I - 5. 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 by filling available existing firm capacity before adding incremental capacity. Note that unlike the
2010 IRP, the Idaho Falls satellite LNG is not utilized in any period.
Storage Resources
The JP (resources 14 and 15) and Clay Basin (18 - 20) are fully utilized, or nearly so, in periods I - 8 and
are completely withdrawn on an annual basis. The Plymouth LS peaking contracts (resources 16 and 17)
are utilized in periods I - 5 only (the five coldest days) and approximately 12% of the total inventory is
withdrawn. Intermountain's LNG facility, the top stack of all supply resources, shows no withdrawal in any
period. As loads continue to grow, further utilization of all liquid storage facilities can be expected.
All storage except LNG is fully withdrawn during the peak day. JP and Clay Basin are released as part an
AMA agreement and are from an operating standpoint, treated as a gas purchase. Therefore storage
injections that occur in the summer period only reflect LNG liquefaction. After factoring in fuel losses, total
injections match the withdrawals in the other periods for each facility. 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.
DSM
Because the low levels of natural gas prices erode any value of DSM against gas purchases, no DSM
resource was assumed in this IRP.
Capacity
All existing NWP firm capacity is fully utilized in periods 1 -5 which suggests that as future loads grow and
LNG withdrawals reach maximum potential, Intermountain might require incremental capacity. No deficits
occur on any the constraint zones on the distribution system.
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 2013 discounted
variable resource costs are $565.3 million.
Intermountain Gas Company
2013-2017 Integrated Resource Plan
DESIGN BASE CASE - YEAR 5 (SEE EXHIBIT No. 4, TABLE 5.5)
Supply Resources
The existing supply resources (contracts 3 - 9) are still fully utilized except that resources 2 and 8 (both
Citygate resources) have terminated and have not been replaced. The industrial Resources 25-28 are
now at zero reflecting that capacity release to these customers had been discontinued while resources 29
and 30 still 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
utilized during periods I - 12. Rockies spot (46 and 60-62) are heavily utilized all year long including the
summer months.
Storage Resources
The JP (resources 14 and 15) and Clay Basin (18 - 20) are fully utilized, or nearly so, in periods I - 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 339,647 0th or 31% of the total inventory. While Intermountain's
LNG facility still shows zero withdrawals, about 80% of the total Plymouth LS storage is used on the peak
day 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.
The satellite storage facility on the IFL and not used at all reflected the Phase V Idaho Falls lateral
expansion. No other "fill-type" resources are needed on any of the Company's laterals in any period.
DSM
Again, no DSM resource was assumed in this IRP.
Capacity
All existing NWP firm capacity is fully utilized for periods 1-5, Stanfield capacity through period 7 and
Rockies capacity through period 8... The model selects 9,786 Dth/day of incremental Rockies capacity
which points out that because some of the Company's Rockies capacity is projected to terminate, total
winter deliveries of Clay Basin withdrawals is affected. If the model had no additional capacity available,
it would have likely not been able to withdraw all Clay Basin volumes and would make up the difference
with the more costly Plymouth and Nampa withdrawals. This suggests that the Intermountain needs to
procure more Rockies capacity (which is unlikely), reduce the amount of term Rockies supply/storage
volumes, or find a third party to "swap" volumes between Rockies and Stanfield or Sumas. No deficits
occur on any the constraint zones and no lateral specific resources are utilized.
Annual Cost Summary
Per the last sheet of Exhibit No. 4, Table 5.5, the grand total of all 2017 discounted resource costs are
$565.3 million.
Intermountain Gas Company
2013-2017 Integrated Resource Plan
COMPARATIVE ANALYSIS 2012 IRP VS. 2010 IRP
RESIDENTIAL AND COMMERCIAL GROWTH FORECAST
The methodology used to calculate residential and commercial customers for the 2012 IRP is consistent
with that used in the 2010 IRP. However, customer growth in the 2012 IRP is forecast to be more
moderate than in the 2010 IRP, mainly due to the continuing recession and its corresponding downturn in
housing construction. On average, the 2012 IRP total customer growth forecast for the three-year period
common to both the 2010 and the 2012 IRP's, 2013 through 2015, is 44% less than that which was
forecast for the preceding 2010 IRP. The current five-year customer growth is now forecast at an annual
rate of 1.3% compared to the previous IRP's 2.2%. The 2013 beginning customer figure of 314,603 per
the 2012 IRP is 6,562 customers lower than the 2013 projection of 321,165 found in the 2010 Plan. A
comparison of the Customer Forecast and Conversion Forecast for the previous two IRP filings compared
to actual can be found in Attachment 1, Tables 1.1 and 1.2.
USAGE PER CUSTOMER WITH DESIGN DEGREE DAYS
The method of calculating the design degree days in the 2012 IRP was the same as the method used in
2010.
The peak usage per customer equations for the 2010 IRP were based upon data from 1989 through
2009. In the 2012 IRP, Intermountain determined that a shorter data series provided a better statistical
fit. Thus, a time period of 2000 through 2010 was used. The shorter time series helps to account for
structural shifts that have occurred in the data. Intermountain also tested two new explanatory variables:
IGC WACOG and County Specific Number of Persons per Household. In the non-peak month models,
Intermountain tested two additional variables: Average Home Sales Price and Days on the Market for
Home Sales.
As in prior IRP Plans, Intermountain also tested the distribution system segments for differences in usage
patterns. There is finally enough data available for the Sun Valley Lateral to generate a unique,
statistically significant regression model based on that lateral's usage patterns. The new equation
includes daily actual HDD65 and daily snowfall totals as explanatory variables. The remaining segments
all continue to use the total company equations applied to segment specific degree days.
INDUSTRIAL FORECAST
Energy conservation is a very high priority for industrial customers to maximize production and output in
order to stay competitive. Industrial customers 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 2012 IRP has increased 9.3% over the
2010 IRP as a result of customer additions and contract changes. However, the compound rate of growth
in annual usage of 0.268% is down from 2.18% in the 2010 IRP. (See Attachment No. 2, Tables 2.1 -
2.3).
LOAD DEMAND CURVES
The total company Core market sendout forecast for 2013-2015 is lower than 2010's IRP by a range of
3.8% - 5.5%. A comparison of usage forecast for the past two IRP filings compared with actual usage
can be found on Attachment 1, Table 1.3. The overall peak day sendout for the same period is slightly
less at a 4.8% - 6.3% decrease (See Attachment 3, Table 3.3). The 2012 IRP reflects no peak day firm
delivery differences for 2013, 2014 or 2015. Total storage deliveries are projected to remain the same as
identified in the 2010 IRP (See Attachment 3, Table 3.6). There are no occurrences where the projected
peak demand exceeds peak deliverability. (See Attachment No. 3, Table 3.7).
Intermountain Gas Company
2013-2017 Integrated Resource Plan
Idaho Falls Lateral. The 2012 IRP reflects a decrease in peak demand for 2013-2015 of between 1.8%
and 2.9% when compared to the 2010 IRP (See Attachment No. 3, Table 3.12). Due to the Phase 5
project, which increased deliverability, there are no occurrences where the projected peak demand
exceeds peak deliverability (See Attachment No. 3, Table 3.15).
Sun Valley Lateral. Peak loads decrease by 6.5% - 7.2% for years 2013-2015 when compared to the
2010 IRP. The fact that there is no growth in industrial CD highlights the decrease in Core market growth
in this region (See Attachment No. 3, Table 3.22). There are no occurrences where the projected peak
demand exceeds peak deliverability. In 2011, Intermountain Gas Company installed a compressor station
which added additional capacity, eliminating any potential peak deficits (See Attachment No. 3, Table
3.23).
Canyon County. The 2012 IRP showed a reduction in peak day usage by approximately 7.9% on
average when compared to the 2010 IRP. Another interesting note is that in the 2012 IRP there are no
projected deficits (See Attachment No. 3, Table 3.33).
State Street Lateral. Peak loads decrease by 3.6% - 4.4% for years 2013-2015 when compared to the
2010 IRP (See Attachment No. 3, Table 3.42). There are no occurrences where the projected peak
demand exceeds peak deliverability (See Attachment No. 3, Table 3.45).
TRADITIONAL SUPPLY AND DELIVERY RESOURCES
The 2012 optimization model includes flexibility for a total of 100 distinct supply resources, the same
number utilized in the 2010 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. satellite 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 2010 filing, 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 FY17.
The resource optimization model allows the user to input up to 30 Interstate transport resources. The
2012 model continues to include the capacity requirements and constraints associated with the new
"State Street" area.
The 2008 IRP indicated that the customer growth assumptions resulted in rapidly growing demand for
winter and/or peak resources. The Company actively monitored the market for capacity and storage
opportunities and was able to add new liquid storage capacity to its contracted portfolio that was included
in its 2010 IRP. With the slower customer growth experienced since 2007, the current models indicate
that the current levels of capacity and storage fully satisfy the Company's needs through 2017 even under
Design weather and high growth conditions.
NON-TRADITIONAL SUPPLY RESOURCES
The 2012 IRP continued to utilize the expanded research and definitions of non-traditional resources that
were originally introduced in the 2008 IRP. The options included in the 2012 are fuel oil, coal, wood chips,
propane, pipeline looping, remote or satellite LNG, compressor stations and pipeline uprating. The
included pipeline looping and uprating, along with additional compressor station research, fall into the
sub-section named "Capacity Upgrades"; which is now included in the Non-Traditional Supply Resources
section.
DISTRIBUTION SYSTEM
Intermountain used the same software utilized in 2010 to model the pressure and capacity of the
individual distribution systems. This software has the capability 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
go
Intermountain Gas Company
2013-2017 Integrated Resource Plan
capacities for any projected scenario on the State Street Lateral, Idaho Falls Lateral, Sun Valley Lateral
and Canyon County area; which are then utilized 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 mailing 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 ability 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 that emphasize conservation, 5) continued
to deploy and improve an 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)
continue to partner with various agencies on conservation information outreach.
DEMAND-SIDE MANAGEMENT
IGC updated the Navigant DSM study used in 2010 IRP to reflect current market conditions, efficiency
assumptions, and natural gas costs. The price for natural gas has dropped significantly since the 2010
IRP filing. In addition, U.S. Department of Energy standards mandating higher, region-based minimum
efficiency standards for residential water heaters will increase to .62 EF in 2015.
In the 2010 IRP, Intermountain had proposed three new rebate pilot programs. Because of the changes
in market conditions, none of the proposed programs were implemented. The lower natural gas prices,
which are expected to remain low at least through Intermountain's next IRP filing, put the proposed DSM
programs below the TRC threshold for cost effectiveness. Intermountain will continue to evaluate DSM
opportunities through its ongoing IRP planning process.
RESOURCE OPTIMIZATION
Intermountain utilized the same consultant and software vendor to run the 2012 optimization as was used
for the 2010 IRP. No new constraint areas were added to the 2012 model. The enhanced model
continues to provide more than adequate capability to input supply, storage, capacity and DSM
resources.
The results of the optimization runs indicate that the Company's current resource portfolio of interstate
transport and storage capacity along with its term supplies and available spot gas supplies, are adequate
to meet the natural gas demands of southern Idaho. It does suggest that, while peaking storage is
adequate, the increased reliance on spot supplies for baseload winter supplies could mean there is room
for additional layer(s) of term supply contracts. Interstate capacity is sufficient in every period.
Previous IRP's pointed out parts of the distribution system that had, or were reaching, their maximum
peak demand capabilities. Consequently, the Company responded by adding capacity in areas such as
the Idaho Falls and Sun Valley laterals. As a result, this IRP showed no areas of the distribution system
that required the selection of incremental distribution system enhancements (e.g. various pipe expansions
and compression upgrades) or non-traditional resources to meet all Design loads through 2017.
When the Optimization model was run using demand from the Design weather, Base Case demand and
price scenario, the model showed that the Company's planned resources met all forecasted design firm
loads and left no on-system capacity deficits over the 5-year horizon. Thus the Company's portfolio of
supply, storage, and capacity resources is sufficient through 2017 to meet the firm requirements of
Intermountain's customers even under Design weather conditions.
Intermountain Gas Company
2013 - 2017 Integrated Resource Plan
ATTACHMENT NO. I
Forecast vs. Actual Comparisons
Table 1.1
Comparison of IRP Conversion Forecasts to Actual
---im
2008 IRP Forecast 713 705 • 69 694 695
RSI 542 542 54 5431 5431
RS2 111 105 97 93 94 ______
GS 60 585 58 58
2010 IRP Forecast __
• 58 650 678 - 74 8491 _____
RS2 70 941 9111 981 1111
GS 46 591 64 66 7
2012 IRP Forecast 5461 6021 5891 5811 552
RSI 411 761 681 661 64
RS2 4511 4641 459 453 434
GS 54 621 621 621 54
Actual conversions - 518 627 703 863
RSI 346 444 496 582
RS2 107 111 136 196
GS 65 72 71 85
Table 1.2
Comparison _IRP_ Customer _Forecasts (S,Ies) to Actual
2 Forecast 109000 10,000 10,000 10,000 10,000 1 9
RSI 1 5421 5421 5421 5431 5431
RS2 1 8,6251 8,6251 8,625 8,6241 8,6241
GS 1 6m 8331 8331 833 8331 83 _ 2010 IRP Forecast
RSI 4701 497 5231 578 667
RS2 5,1301 5,563 5,777 6,402 7,363
GS
--_-_
5001 6401 700 720 7701 1
2012 IRP Forecast 4,1001 4,5501 4,5001 4,5001 4,300
RSI 4181 4641 4591 4521 435
RS2 3,3821 3,736 3,691 3,693 3,553
GS 1 300 350 350 355 312
Actual sales 3,689 3,358 2,961 4,38
RSI 429 530 544 64
RS2 2,956 2,554 2,152 3,426
GS 304 274 265 318
F:,'
Intermountain Gas Company
2013-2017 Integrated Resource Plan
Table 1.3
Comparison of IRP Usage Forecasts to Actual
(000's of Dktherms)
2 IRP_FORECAST I
Normal Wx 1 32,8591 33,8841 34,9041 36,1251 36,8581
Design Wx 0 38,594 39,796 43,302

40,994 42,352
2010IRP FORECAST
Normal Wx 33,521 34,0451 34,4801 35,1821 35,870
"
Design Wx 6= 1 39,1851
2012 IRP_FORECAST
39,8231 40,3521 41,1941 42,007
Normal Wx 30,489 30,747 31,035 31,320 31,606
Design Wx 35,928 36,381 36,876 37.3641 37,853
Actual Usage 1 32,4641 30,295 33,541 29,9901
88
Intermountain Gas Company
2013 - 2017 Integrated Resource Plan
ATTACHMENT NO. 2
Industrial Forecast by Market Segment 2012 IRP vs. 2010 IRP
Table 2.1
2012 IRP Design Base Case Industrial Forecast by Market Segment
(Thousands of Therms)
2013 2014 2015
Potato Processors 88,275 89,275 89,275
Other Food Processors 66,315 65,385 65,385
Chemical & Fertilizer 23,338 23,338 23,338
Manufacturers 17,035 17,435 17,635
Institutions 19,554 20,456 20,381
Other 30,014 30,014 30,015
Total Base Case Forecast Therm Sales 1 244,531 1 245,903 246,029
Table 2.2
2010 IRP Design Base Case Industrial Forecast by Market Segment
(Thousands of Therms)
2013 2014 2015
Potato Processors 92,148 92,218 92,228
Other Food Processors 68,340 68,320 68,300
Chemical & Fertilizer 30,440 30,440 30,440
Manufacturers 18,417 18,567 18,717
Institutions 15,064 15,097 15,177
Other 24,456 24,484 24,494
Total Base Case Forecast Therm Sales 248,865 249,126 249,356
Table 2.3
2010 IRP Design Base Case Industrial Forecast by Market Segment
Over/(Under) the 2008 IRP Design Base Case
(Thousands of Therms)
2013 2014 2015
Potato Processors (3,873) (2,943) (2,953)
Other Food Processors (2,025) (2,935) (2,915)
Chemical & Fertilizer (7,102) (7,102) (7,102)
Manufacturers (1,382) (1,132) (1,082)
Institutions 4,490 5,359 5,204
Other 5,558 5,530 5,521
Total Base Case Forecast Therm Sales (4,334) (3,223)
Intermountain Gas Company
2013-2017 Integrated Resource Plan
ATTACHMENT NO.3
Total Company Design Weather/Base Growth 2012 IRP vs. 2010 IRP Usage
Comparison
Table 3.1
2012 IRP LOAD DEMAND CURVE - TOTAL COMPANY USAGE DESIGN BASE CASE
(Volumes in Therms)
NWP Firm Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD I2t!
2013 2,781,100 3,577,098 146,113 3,723,211
2014 2,751,950 3,622,449 146,113 3,768,562
2015 2,651,950 3,671,923 146,113 3,818,036
'Future growth in transport CD is limited to 1-4, which does not affect Intermountain's interstate pipeline capacity requirements.
Table 3.2
2010 IRP LOAD DEMAND CURVE - TOTAL COMPANY USAGE DESIGN BASE CASE
(Volumes in Therms)
NWP Firm Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD' Total
2013 2,736,250 3,718,077 190,010 3,908,087
2014 2,728,740 3,801,170 190,010 3,991,180
2015 2,699,590 3,882,776 190,010 4,072,786
'Future growth in transport CD is limited to 1-4, which does not affect Intermountain's interstate pipeline capacity requirements.
Table 3.3
2012 IRP LOAD DEMAND CURVE - TOTAL COMPANY DESIGN BASE CASE
Over/(Under) 2010 IRP
(Volumes in Therms)
NWP
Firm Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD' Total
2013 44,850 (140,979) (43,897) (184,876)
2014 23,210 (178,721) (43,897) (222,618)
2015 (47,640) (210,853) (43,897) (254,750)
'Future growth in transport CD is limited to 1-4, which does not affect Intermountain's interstate pipeline capacity requirements.
EX
Intermountain Gas Company
2013-2017 Integrated Resource Plan
ATTACHMENT NO. 3
Total Company Peak Day Deliverability Comparison for 2012 IRP vs. 2010 IRP
Table 3.4
2012 IRP PEAK DAY FIRM DELIVERY CAPABILITY
(Volumes in Therms)
2013 2014 2015
Maximum Daily Storage Withdrawals:
Nampa LNG 600,000 600,000 600,000
Plymouth LS 1,132,000 1,132,000 1,132,000
Jackson Prairie SGS 303.370 303.370 303,370
Total Storage 2,035,370 2,035,370 2,035,370
Maximum Deliverability (NWP) 2.780.110 2,751.950 2.651.950
Total Peak Day Deliverability
Table 3.5
2010 IRP PEAK DAY FIRM DELIVERY CAPABILITY
(Volumes in Therms)
2013 2014 2015
Maximum Daily Storage Withdrawals:
Nampa LNG 600,000 600,000 600,000
Plymouth LS 1,132,000 1,132,000 1,132,000
Jackson Prairie SGS 303,370 303.370 303,370
Total Storage 2,035,370 2,035,370 2,035,370
Maximum Deliverability (NWP) 2,736,250 2.728,740 2,699,590
Total Peak Day Deliverability
Table 3.6
2012 IRP PEAK DAY FIRM DELIVERY CAPABILITY
Over/(Under) 2010 IRP
(Volumes in Therms)
2013 2014 2015
Maximum Daily Storage Withdrawals:
Nampa LNG 0 0 0
Plymouth LS 0 0 0
Jackson Prairie SGS 0 0 0
Total Storage 0 0 0
Maximum Deliverability (NWP) 43,860 23.210 (47.640)
Total Peak Day Deliverability (41.980' (63.620 (134.470
91
Intermountain Gas Company
2013-2017 Integrated Resource Plan
ATTACHMENT NO. 3
Total Company Peak Delivery Deficit for 2012 IRP vs. 2010 IRP
Table 3.7
2012 IRP FIRM DELIVERY DEFICIT - TOTAL COMPANY DESIGN BASE CASE
(Volumes in Therms)
2013 2014 2015
Peak Day Deficit 0 0 0
Total Winter Deficit' 0 0 0
Days Requiring Additional Resources 0 0 0
'Equal 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.
Table 3.8
2010 IRP FIRM DELIVERY DEFICIT -TOTAL CO MPANY DESIGN BASE CASE
(Volumes in Therms)
2013 2014 2015
Peak Day Deficit' 0 0 0
Total Winter Deficit2 0 0 0
Days Requiring Additional Resources 0 0 0
'Peaking storage increased by 78,370 therms per day in 2010.
2Equal to the total winter sendout in excess of interstate capacity less total "peaking" storage. Peaking storage does not
require the use of lntermountains traditional interstate capacity to deliver inventory to the citygate.
Table 3.9
2012 IRP FIRM DELIVERY DEFICIT - TOTAL COMI 'ANY DESIGN BASE CASE
Over/(Under) 2010 IRP
(Volumes in Therms)
2013 2014 2015
Peak Day Deficit' 0 0 0
Total Winter Deficit 2 0 o o
Days Requiring Additional Resources 0 0 0
'Peaking storage increased by 78,370 therms per day in 2010.
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.
92
Intermountain Gas Company
2013-2017 Integrated Resource Plan
ATTACHMENT NO. 3
Idaho Falls Lateral Design Weather/Base Growth Comparison for 2012 IRP vs.
2010 IRP
Table 3.10
2012 LOAD DEMAND CURVE - IDAHO FALLS DESIGN BASE CASE
(Volumes in Therms)
Existing
Distribution Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD' Total
2013 999,000 651,552 239,550 891,102
2014 999,000 661,453 239,550 901,003
2015 999,000 672,116 239,550 911,666
'Existing firm contract demand includes T4 and T-5 requirements.
Table 3.11
2010 LOAD DEMAND CURVE - IDAHO FALLS DESIGN BASE CASE
(Volumes in Therms)
Existing
Distribution Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD' Total
2013 810,000 685,566 221,750 907,316
2014 810,000 703,123 221,750 924,873
2015 810,000 716,620 221,750 938,370
'Existing firm contract demand includes T-4 and T-5 requirements.
Table 3.12
2012 LOAD DEMAND CURVE - IDAHO FALLS DESIGN BASE CASE
Over/(Under) 2010 IRP
(Volumes in Therms)
Existing
Distribution Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD1 Total
2013 189,000 (34,014) 17,800 (16,214)
2014 189,000 (41,670) 17,800 (23,870)
2015 189,000 (44,504) 17,800 (26,704)
'Existing firm contract demand includes includes T-4 and T-5 requirements.
93
Intermountain Gas Company
2013-2017 Integrated Resource Plan
ATTACHMENT NO. 3
Idaho Falls Lateral Delivery Deficit Comparison for 2012 IRP vs. 2010 IRP
Table 3.13
2010 IRP FIRM DELIVERY DEFICIT - IDAHO FALLS DESIGN BASE CASE
(Volumes in Therms)
2013 2014 2015
Peak Day Deficit' 0 0 0
Total Winter Deficit 0 0 0
Days Requiring Additional Capacity 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
Table 3.14
2010 IRP FIRM DELIVERY DEFICIT - IDAHO FALLS DESIGN BASE CASE
(Volumes in Therms)
2013 2014 2015
Peak Day Deficit' 97,320 114,870 128,370
Total Winter Deficit 178,490 240,800 281,460
Days Requiring Additional Capacity 3 4 4
'Equal to the total winter sendout in excess of distribution capacity.
Table 3.15
2012 IRP FIRM DELIVERY DEFICIT - IDAHO FALLS DESIGN BASE CASE
Over/(Under) 2010 IRP
(Volumes in Therms)
2013 2014
Peak Day Deficit' (97,230) (114,870) (128,370)
Total Winter Deficit2 (178,490) (240,800) (281,460)
Days Requiring Additional Capacity 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
94
Intermountain Gas Company
2013-2017 Integrated Resource Plan
ATTACHMENT NO. 3
Sun Valley Lateral Design Weather/Base Growth Comparison for 2012 IRP vs.
2010 IRP
Table 3.20
2012 IRP LOAD DEMAND CURVE - SUN VALLEY DESIGN BASE CASE
(Volumes in Therms)
Existing
Distribution Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD1 Total
2013 204,000 164,691 8,150 172,841
2014 204,000 165,837 8,150 173,987
2015 204,000 167,562 8,150 175,712
'Existing firm contract demand includes T-4 and T-5 requirements.
Table 3.21
2010 IRP LOAD DEMAND CURVE - SUN VALLEY DESIGN BASE CASE
(Volumes in Therms)
Existing
Distribution Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD' IQI
2013 175,000 176,554 8,150 184,704
2014 175,000 178,846 8,150 186,996
2015 175,000 181,053 8,150 189,203
'Existing firm contract demand includes T.4 and T-5 requirements.
Table 3.22
2012 IRP LOAD DEMAND CURVE - SUN VALLEY DESIGN BASE CASE
Over/(Under) 2010 IRP
(Volumes in Therms)
Existing
Distribution Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD1 Total
2013 29,000 (11,863) 0 (11,863)
2014 29,000 (13,009) 0 (13,009)
2015 29,000 (13,491) 0 (13,491)
'Existing firm contract demand includes T-4 and T-5 requirements.
95
Intermountain Gas Company
2013-2017 Integrated Resource Plan
ATTACMENT NO. 3
Sun Valley Lateral Delivery Deficit Comparison for 2012 IRP vs. 2010 IRP
Table 3.23
2012 IRP FIRM DELIVERY DEFICIT - SUN VALL EY DESIGN BASE CASE
(Volumes in Therms)
2013 2014 2015
Peak Day Deficit' 0 0 0
Total Winter Deficit 2 0 0 0
Days Requiring Additional Capacity 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
Table 3.24
2010 IRP FIRM DELIVERY DEFICIT - SUN VA L.LEY DESIGN BASE CASE
(Volumes in Therms)
2013 2014 2015
Peak Day Deficit' 9,700 12,000 14,200
Total Winter Deficit2 17,790 24,570 30,220
Days Requiring Additional Capacity 3 3 4
'Equal to the total winter sendout in excess of distribution capacity.
Table 3.25
2012 IRP FIRM DELIVERY DEFICIT - SUN VALLEY DESIGN BASE CASE
Over/(Under) 2010 IRP
(Volumes in Therms)
2013 2014
Peak Day Deficit' (9,700) (12,000) (14,200)
Total Winter Deficit2 (17,790) (24,570) (30,220)
Days Requiring Additional Capacity 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
Intermountain Gas Company
2013-2017 Integrated Resource Plan
ATTACHMENT NO. 3
Canyon County Area Design Weather/Base Growth Comparison for 2012 IRP vs.
2010 IRP
Table 3.30
2012 LOAD DEMAND CURVE - CANYON COUNTY DESIGN BASE CASE
(Volumes in Therms)
Existing
Distribution Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD1 Total
2013 680,000 509,640 93,310 602,950
2014 680,000 518,161 93,310 611,471
2015 680,000 527,575 93,310 620,885
'Existing firm contract demand includes T-4 and T-5 requirements.
Table 3.31
2010 LOAD DEMAND CURVE - CANYON COUNTY DESIGN BASE CASE
(Volumes in Therms)
Existing
Distribution Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD' Total
2013 690,000 544,680 102,500 647,180
2014 690,000 561,428 102,500 663,928
2015 690,000 578,274 102,500 680,774
'Existing firm contract demand includes T-4 and T-5 requirements.
Table 3.32
2012 LOAD DEMAND CURVE - CANYON COUNTY DESIGN BASE CASE
Over/(Under) 2010 IRP
(Volumes in Therms)
Existing
Distribution Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD1 Total
2013 (10,000) (35,040) (9,190) (44,230)
2014 (10,000) (43,267) (9,190) (54,457)
2015 (10,000) (50,699) (9,190) (59,889)
'Existing firm contract demand includes T-4 and T-5 requirements.
97
Intermountain Gas Company
2013 - 2017 Integrated Resource Plan
ATTACHMENT NO. 3
Canyon County Area Firm Delivery Deficit Comparison for 2012 IRP vs. 2010 IRP
Table 3.33
2012 IRP FIRM DELIVERY DEFICIT - CANYON CC )UNTY DESIGN BASE CASE
(Volumes in Therms)
2013 2014 2015
Peak Day Deficit' 0 0 0
Total Winter Deficit 0 0 0
Days Requiring Additional Capacity 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
Table 3.34
2010 IRP FIRM DELIVERY DEFICIT - CANYON COUNTY DESIGN BASE CASE
(Volumes in Therms)
2013 2014 2015
Peak Day Deficit' 0 0 0
Total Winter Deficit 0 0 0
Days Requiring Additional Capacity 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
Table 3.35
2012 IRP FIRM DELIVERY DEFICIT - CANYON COUNTY DESIGN BASE CASE
Over/(Under) 2010 IRP
(Volumes in Therms)
2013 2014 2015
Peak Day Deficit' 0 0 0
Total Winter Deficit 0 0 0
Days Requiring Additional Capacity 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
Intermountain Gas Company
2013-2017 Integrated Resource Plan
ATTACHMENT NO. 3
State Street Area Design Weather/Base Growth Comparison for 2012 IRP vs. 2010
IRP
Table 3.40
2012 LOAD DEMAND CURVE - STATE STREET DESIGN BASE CASE
(Volumes in Therms)
Existing
Distribution Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD1 Total
2013 585,000 500,622 16,000 516,622
2014 585,000 505,659 16,000 521,659
2015 585,000 510,729 16,000 526,729
'Existing fimi contract demand includes T-4 and T-5 requirements.
Table 3.41
2010 LOAD DEMAND CURVE - STATE STREET DESIGN BASE CASE
(Volumes in Therms)
Existing
Distribution Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD1 Total
2013 585,000 519,276 17,100 536,376
2014 585,000 526,531 17,100 543,631
2015 585,000 534,459 17,100 551,559
'Existing firm contract demand includes T-4 and T-5 requirements.
Table 3.42
2012 LOAD DEMAND CURVE - STATE STREET DESIGN BASE CASE
Over/(Under) 2010 IRP
(Volumes in Therms)
Existing
Distribution Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD1 Total
2013 0 (18,654) (1,100) (19,754)
2014 0 (20,872) (1,100) (21,972)
2015 0 (23,730) (1,100) (24,830)
'Existing firm contract demand includes T-4 and T-5 requirements.
99
Intermountain Gas Company
2013-2017 Integrated Resource Plan
ATTACHMENT NO. 3
State Street Area Firm Delivery Deficit Comparison for 2012 IRP vs. 2010 IRP
Table 3.43
2012 IRP FIRM DELIVERY DEFICIT - STATE STREET DESIGN BASE CASE
(Volumes in Therms)
2013 2014 2015
Peak Day Deficit' 0 0 0
Total Winter Deficit 0 0 0
Days Requiring Additional Capacity 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
Table 3.44
2010 IRP FIRM DELIVERY DEFICIT - STATE STREET DESIGN BASE CASE
(Volumes in Therms)
2013 2014 2015
Peak Day Deficit' 0 0 0
Total Winter Deficit 0 0 0
Days Requiring Additional Capacity 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
Table 3.45
2012 IRP FIRM DELIVERY DEFICIT - STATE STREET DESIGN BASE CASE
Over/(Under) 2010 IRP
(Volumes in Therms)
2013 2014 2015
Peak Day Deficit' 0 0 0
Total Winter Deficit 0 0 0
Days Requiring Additional Capacity 0 0 0
'Equal to the total winter sendout in excess of distribution capacity.
100
Intermountain Gas Company
2013-2017 Integrated Resource Plan
ATTACHMENT NO. I
Total Company Firm Receipt Point Capacity Comparison for 2012 IRP Vs. 2010
IRP
Table 3.50
Intermountain Gas Company
2012 IRP Firm Receipt Point Capacity Through 2015
Volumes in MMBtu
Receipt Point 2013 2014
Sumas 27,832 27,832 27,832
Stanfield 151,284 149,120 152,035
Rockies 73,994 73,243 70,328
Storage 194,854 194,854 194,854
itygate 25,000 25.000 15,000
Total 472,964 470,049 460,049
Table 3.51
Intermountain Gas Company
2010 IRP Firm Receipt Point Capacity Through 2015
Volumes in MMBtu
Receipt Point 201 2014 201..
%mas 41,146 41,146 41,146
Stanfield 115,429 115,429 115,429
Rockies 91,050 90,249 87,384
Storage 203,537 203,537 203,537
itygate 26,000 26,000 26,000
Total 477,162 476,361 473,496
Table 3.52
Intermountain Gas Company
2013 IRP Firm Receipt Point Capacity Through 2015
Over! (Under) 2010 IRP
Volumes in MMBtu
Receipt Point 201 2014 201
Sumas (13,314) (13,314) (13,314)
Stanfield 35,855 33,691 36,606
Rockies (17,056) (17,006) (17,056)
Storage (8,683) (8,683) (8,683)
itygate (1,000) (1,000) (11,000)
rotal (4,198) (6,312) (13,447)
101