HomeMy WebLinkAbout20170804Application Summary.pdfEXECUTIVE OFFICES
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5s5 SOUTH COLE ROAD . p.O. BOX 7608 . BO|SE, TDAHO 83707 . (208) 377-6000 o FAX:377-6097
August 4,2077
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Ms. Diane Hanian
Commission Secretary
ldaho Public Utilities Commission
472 W. Washington Street
P.O. Box 83720
Boise, lD 83720-0074
RE:lntermountain Gas Company's 2017 lntegrated Resource Plan
Case No. INT-G-17-04
Dear Ms. Hanian:
Enclosed for filing with this Commission are the original and seven (7) copies of lntermountain
Gas Company's2OL7 lntegrated Resource Plan.
lf you have any questions or require additional information regarding the attached, please
contact me at 377-6L68.
Very truly yours,
P
irector - Regulatory Affairs
Enclosures
cc: Scott Madison
Mark Chiles
Ronald L. Williams
Intermountain Gas Company
2017-2021 Integrated Resource Plan
August 2017
INTERMOUNTAIN GAS COMPANY
Integrated Resource Plan 2017-2021
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 1 of 111
Table of Contents
EXECUTIVE SUMMARY .............................................................................................................................. 2
DEMAND FORECAST OVERVIEW ........................................................................................................... 13
RESIDENTIAL AND COMMERCIAL CUSTOMER GROWTH FORECAST ............................................. 14
HEATING DEGREE DAYS AND DESIGN WEATHER .............................................................................. 33
USAGE PER CUSTOMER ......................................................................................................................... 37
LARGE VOLUME CUSTOMER FORECAST ............................................................................................. 39
TRADITIONAL SUPPLY-SIDE RESOURCES ........................................................................................... 46
NON-TRADITIONAL SUPPLY RESOURCES ........................................................................................... 62
CAPACITY RELEASE AND MITIGATION PROCESS .............................................................................. 68
DISTRIBUTION SYSTEM MODELING ...................................................................................................... 70
AVAILABLE AND POTENTIAL SYSTEM CAPACITY ENHANCEMENTS .............................................. 72
THE EFFICIENT AND DIRECT USE OF NATURAL GAS ........................................................................ 74
LOST AND UNACCOUNTED FOR NATURAL GAS MONITORING ........................................................ 80
DEMAND SIDE MANAGMENT .................................................................................................................. 83
LOAD DEMAND CURVES ......................................................................................................................... 87
NON-UTILITY LNG FORECAST .............................................................................................................. 107
INFRASTRUCTURE REPLACEMENT .................................................................................................... 110
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 2 of 111
INTERMOUNTAIN GAS COMPANY
INTEGRATED RESOURCE PLAN
EXECUTIVE SUMMARY
Natural gas continues to be the fuel of choice in Idaho. Southern Idaho's manufacturing plants,
commercial businesses, new homes and anticipated new electric power plants, all rely on natural gas to
provide an economic, efficient, environmentally friendly, comfortable form of heating energy.
Intermountain Gas Company ("Intermountain" or “IGC”) endorses and encourages the wise and efficient
use of energy in general and, in particular, natural gas for high efficient uses in Idaho and Intermountain's
service area. Forecasting the demand of Intermountain's growing customer base is a regular part of
Intermountain's operations, as is determining how to best meet the load requirements brought on by this
demand. Public input is an integral part of this planning process. The customer demand forecast and
resource decision making process is ongoing. This Integrated Resource Plan (“IRP”) document represents
a snapshot in time similar to a balance sheet. It is not meant to be a prescription for all future energy
resource decisions, as conditions will change over the planning horizon impacting areas covered by this
Plan. Rather, this document is meant to describe the currently anticipated conditions over the five-year
planning horizon, the anticipated resource selections and the process for making resource decisions. The
planning process described herein is an integral part of Intermountain's ongoing commitment to make
the wise and efficient use of natural gas an important part of Idaho's energy future.
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
1,260,000. During the fiscal year of 2016, Intermountain served an average of 345,000 customers in 74
communities through a system of over 12,000 miles of transmission, distribution and service lines. Over
169 miles of distribution and service lines were added during 2016 to accommodate new customer
additions and maintain service for Intermountain’s growing customer base.
The economy of Intermountain’s service area is based primarily on agriculture and related industries.
Major crops are potatoes and sugar beets. Major agricultural-related industries include food processing
and production of chemical fertilizers. Other significant industries are electronics, general manufacturing
and services and tourism.
Intermountain provides natural gas sales and service to two major markets: the residential/commercial
market and the industrial market. During 2016, an average of 313,000 residential and 32,000 commercial
customers used natural gas primarily for space and water heating, compared to an average of 281,000
residential and 30,000 commercial customers in 2011. This equates to an increase in average residential
and commercial customers of 2.2% over the past five years.
Intermountain’s industrial customers transport natural gas through Intermountain’s system to be used
for boiler and manufacturing applications. Industrial demand for natural gas is strongly influenced by the
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 3 of 111
LOAD DURATION CURVE - TOTAL COMPANY DESIGN BASE CASE
(Volumes in Therms)
Firm Peak Day Sendout Incremental Peak Day Sendout
2Future growth in transport CD is limited to T-4, which does not affect Intermountain's interstate pipeline capacity requirements.
agricultural economy and the price of alternative fuels. 52% of the throughput on Intermountain’s system
during 2016 was attributable to industrial sales and transportation.
Forecast Peak Day Sendout
Total Company
Residential, commercial and industrial peak day load growth on Intermountain’s system under design
conditions is forecast over the five-year period to grow at an average annual rate of 2.68% under the base case
scenario. The table below summarizes the forecast for peak day sendout under the base case customer growth
assumption.
Transport Core Industrial Core Industrial Capacity1 Market Firm CD Total Market Firm CD2 Total
FY17 5,268,570 3,940,046 37,530 3,977,576
FY18 5,268,570 4,045,010 38,930 4,083,940 106,364 1,400 107,764
FY19 5,268,570 4,155,430 40,930 4,196,360 112,420 1,460 113,880
FY20 5,268,570 4,267,230 40,930 4,308,160 111,800 0 111,800
FY21 5,268,570 4,380,490 40,930 4,421,420 113,260 0 113,260
The above table highlights the fact that growth in the peak day is commensurate with the growth projected to
occur in Intermountain’s residential and small commercial customer markets.
Existing Resources
Intermountain’s existing firm delivery capability on the peak day is made up of the resources shown on the
following page.
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 4 of 111
PEAK DAY FIRM DELIVERY CAPABILITY
(Volumes in Therms)
FIRM DELIVERY DEFICIT – TOTAL COMPANY DESIGN BASE CASE
(Volumes in Therms)
1Equal to demand less all available supply and delivery resources.
Maximum Daily Storage Withdrawals:
FY17 FY18 FY19 FY20 FY21
Nampa LNG 600,000 600,000 600,000 600,000 600,000
Plymouth LS 1,551,750 1,551,750 1,551,750 1,551,750 1,551,750
Jackson Prairie SGS 303,370 303,370 303,370 303,370 303,370
Total Storage 2,455,120 2,455,120 2,455,120 2,455,120 2,455,120
Maximum Deliverability (NWP) 2,813,450 2,813,450 2,813,450 2,813,450 2,813,450
Total Peak Day Deliverability 5,268,570 5,268,570 5,268,570 5,268,570 5,268,570
When forecasted peak day sendout is matched against existing resources, there are no peak day delivery
deficits.
FY17 FY18 FY19 FY20 FY21
Peak Day Deficit 1 0 0 0 0 0
Total Winter Deficit1 0 0 0 0 0
Days Requiring Additional Resources 0 0 0 0 0
Regional Studies
Certain geographic regions within Intermountain’s service territory were analyzed based upon the anticipated
or potential need for distribution system upgrades within each specific region. Not unlike the total company
interstate mainline perspective, the projected peak day sendout for each region was measured against the
known distribution capacity and resources 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 were also included as part of these
regional studies. A wide array of alternatives were evaluated in formulating the best plan to meet the projected
deficits in the various regions within Intermountain’s service territory (see “Non-Traditional Supply Resources”
- Page 62).
Additionally, each region is analyzed within the framework of the Company’s Distribution System Model (See
Page 70).
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 5 of 111
LOAD DURATION CURVE - IDAHO FALLS DESIGN BASE CASE
(Volumes in Therms)
Distribution Peak Day Sendout Incremental Peak Day Sendout
1Includes Rexburg LNG Facility for peak day shaving @ 71,000 peak day therms.
2Existing firm contract demand.
3Future growth in transport CD is limited to T-4 which only impacts Intermountain's distribution capacity
Idaho Falls Lateral
The Idaho Falls Lateral (“IFL”) is 104 miles south to north and serves a number of cities between Pocatello in
the south and St. Anthony in the north. The customers served by the IFL represent a diverse base of residential,
commercial and large industrial customers. The residential, commercial and industrial load served off the IFL
represents approximately 15% of the total company customers and 14% of the company’s projected peak
day sendout during January of 2017.
When forecasted peak day sendout on the IFL is matched against the existing IFL peak day capacity, all
peak day demands can be met over the FY15 through FY19 forecast period:
Transport
Capacity1
Core
Market
Industrial
Firm CD2
Total
Core
Market
Industrial
Firm CD3
Total
FY17 887,000 565,520 193,391 758,911
FY18 887,000 582,670 193,391 776,061 17,150 0 17,150
FY19 887,000 599,360 193,391 792,751 16,820 0 16,820
FY20 887,000 618,190 193,391 811,581 18,830 0 18,830
FY21 887,000 637,300 193,391 830,691 19,110 0 19,110
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 6 of 111
FIRM DELIVERY DEFICIT - IDAHO FALLS DESIGN BASE CASE
(Volumes in Therms)
1Equal to demand less all available supply and delivery resources.
FY17 FY18 FY19 FY20 FY21
Peak Day Deficit1 0 0 0 0 0
Total Winter Deficit1 0 0 0 0 0
Days Requiring Additional Resources 0 0 0 0 0
The IFL currently has a portable LNG facility in Rexburg that will be utilized as a peak shaving device to meet
customer demands and supplement firm capacity on the lateral during peak day events. The additional capacity
from Rexburg LNG is planned for use in 2021.
Sun Valley Lateral
The residential, commercial and industrial load served off the Sun Valley Lateral (“SVL”) represents
approximately 3% of the total company customers and 3% of the company’s projected peak day sendout during
January of 2017.
When forecasted peak day sendout on the Sun Valley Lateral is matched against the existing peak day
distribution capacity (199,500 therms), a peak day delivery deficit does not occur during this IRP period. See
table shown on the next page:
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 7 of 111
LOAD DURATION CURVE - SUN VALLEY DESIGN BASE CASE
(Volumes in Therms)
1Existing firm contract demand.
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)
1Equal to demand less all available supply and delivery resources.
Distribution Peak Day Sendout Incremental Peak Day Sendout
Transport
Capacity
Core Industrial
Market Firm CD1Total
Core Industrial
Market Firm CD2 Total
FY17 195,950 153,030 13,350 166,380
FY18 195,950 154,870 13,350 168,220 1,840 0 1,840
FY19 195,950 156,560 13,350 169,910 1,690 0 1,690
FY20 195,950 158,750 13,350 172,100 2,190 0 2,190
FY21 195,950 160,980 13,350 174,330 2,230
0 2,230
FY17 FY18 FY19 FY20 FY21
Peak Day Deficit1 0 0 0 0 0
Total Winter Deficit1 0 0 0 0 0
Days Requiring Additional Resources 0 0 0 0 0
Canyon County Region
The residential, commercial and industrial load in the Canyon County Region (“CCR”) represents approximately
14% of the total core market usage on a projected peak day and 19% of the company’s industrial firm sendout
during January of 2017.
When forecasted peak day sendout for the Canyon County Region is matched against the existing peak day
distribution capacity (860,000 therms – 2019 and 930,000 therms - 2020), a peak day delivery deficit does not
occur during this IRP period. See table on the next page:
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 8 of 111
LOAD DURATION CURVE - CANYON COUNTY DESIGN BASE CASE
(Volumes in Therms)
1Existing firm contract demand.
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)
1Equal to demand less all available supply and delivery resources.
Distribution Peak Day Sendout Incremental Peak Day Sendout
Transport
Capacity
Core Industrial
Market Firm CD1 Total
Core Industrial
Market Firm CD2 Total
FY17 860,000 558,160 263,200 821,360
FY18 860,000 582,390 263,200 845,590 24,230 0 24,230
FY19 860,000 609,210 263,200 872,410 26,820 0 26,820
FY20 930,000 634,720 263,200 897,920 25,510 0 25,510
FY21 930,000 659,970 263,200 923,170 25,250 0 25,250
FY17 FY18 FY19 FY20 FY21
Peak Day Deficit1 0 0 0 0 0
Total Winter Deficit1 0 0 0 0 0
Days Requiring Additional Resources 0 0 0 0 0
While diverse in nature, the industrial customer base served within the CCR currently has limited capability
to switch to alternative fuels as a means of mitigating peak day sendout; Intermountain is currently exploring
additional means of enhancing the distribution capability in this area, mainly with regards to potential biogas
production.
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 9 of 111
LOAD DURATION CURVE – STATE STREET DESIGN BASE CASE
(Volumes in Therms)
Distribution Peak Day Sendout Incremental Peak Day Sendout
1Existing firm contract demand.
2Future growth in transport CD is limited to T-4 which only impacts Intermountain's distribution capacity requirements.
FIRM DELIVERY DEFICIT – STATE STREET DESIGN BASE CASE
(Volumes in Therms)
1Equal to demand less all available supply and delivery resources.
State Street Lateral
The State Street Lateral (“SSL”) is 16.2 miles in length and serves a number of customers in Eagle, Meridian
and the NW Boise area. The customers served by the State Street lateral represent a base of primarily
residential and commercial customers. The residential and commercial load served off the SSL represents
approximately 14% of the total company customers and 15% of the company’s projected core market peak
day sendout during January of 2017.
When forecasted peak day sendout on the SSL is matched against the existing peak day distribution
capacity (670,000 therms – 2019 and 765,000 therms - 2020), a peak day delivery deficit does not occur
during this IRP period. See table below:
Transport Core Industrial Core Industrial Capacity Market Firm CD1 Total Market Firm CD2 Total
FY17 670,000 575,210 17,800 593,010
FY18 670,000 590,710 17,800 608,510 15,500 0 15,500
FY19 670,000 623,080 26,300 649,380 40,870 8,500 49,370
FY20 765,000 656,130 26,300 682,430 33,050 0 33,050
FY21 765,000 672,690 26,300 698,990 16,560 0 16,560
FY17 FY18 FY19 FY20 FY21
Peak Day Deficit1 0 0 0 0 0
Total Winter Deficit1 0 0 0 0 0
Days Requiring Additional Resources 0 0 0 0 0
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 10 of 111
LOAD DURATION CURVE – CENTRAL ADA DESIGN BASE CASE
(Volumes in Therms)
Distribution Peak Day Sendout Incremental Peak Day Sendout
1Existing firm contract demand.
2Future growth in transport CD is limited to T-4 which only impacts Intermountain's distribution capacity requirements.
FIRM DELIVERY DEFICIT – CENTRAL ADA DESIGN BASE CASE
(Volumes in Therms)
1Equal to demand less all available supply and delivery resources.
Central Ada Area
The Central Ada Area (“CAA”) is comprised of multiple high pressure pipeline systems and serves a large
number of customers in the Boise area. The customers served in this area represent a diverse base of
residential and commercial customers. The residential and commercial load served within the area represent
approximately 15% of the total company customers and 12% of the company’s total projected peak day
sendout during January of 2017.
When forecasted peak day sendout from the CAA is matched against the existing peak day distribution
capacity (710,000 therms), a peak day delivery deficit does not occur during this IRP period. See table below:
Transport Core Industrial Core Industrial Capacity Market Firm CD1 Total Market Firm CD2 Total
FY17 710,000 595,060 14,900 609,960
FY18 710,000 606,030 14,900 620,930 10,970 0 10,970
FY19 710,000 617,300 14,900 632,200 11,270 0 11,270
FY20 710,000 628,320 14,900 643,220 11,020 0 11,020
FY21 710,000 639,800 14,900 654,700 11,480 0 11,480
FY17 FY18 FY19 FY20 FY21
Peak Day Deficit1 0 0 0 0 0
Total Winter Deficit1 0 0 0 0 0
Days Requiring Additional Resources 0 0 0 0 0
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 11 of 111
Summary
Residential, commercial and industrial customer growth and their consequent impact on Intermountain’s
distribution system have been analyzed under 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 potential delivery deficits, both
from a total company perspective as well as a regional perspective. The resources needed to meet these
projected deficits were analyzed within a framework of options, both traditional and non-traditional, to help
determine the most cost-effective means available to manage the deficits. In utilizing these options,
Intermountain’s core market and firm transportation customers can continue to rely on uninterrupted firm
service both now and within the planning horizon of this study.
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 12 of 111
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 13 of 111
DEMAND FORECAST OVERVIEW
The first step in resource planning is forecasting future load requirements. Three essential components
of the load forecast include projecting the number of customers requiring service, forecasting the
weather sensitive customers’ response to temperatures and estimating the weather those customers
may experience. To complete the demand forecast, contracted maximum deliveries to industrial
customers are also included.
Intermountain’s long range demand forecast incorporates various factors including divergent customer
forecasts, statistically based gas usage per customer calculations, 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 six separate and diverse demand forecast scenarios for the
weather sensitive core market customers.
Combining those projections with the industrial market forecast provides Intermountain with six total
company demand scenarios that envelop a wide range of potential outcomes. These forecasts not only
project monthly and annual loads but also predict daily usage including peak demand events. The
inclusion of all this detail allows Intermountain to evaluate the adequacy of its supply arrangements and
delivery under a wide range of demand scenarios.
Intermountain’s resource planning looks at distinct segments (also known as Areas of Interest or AOI’s)
within its current distribution system. After analyzing resource requirements at the segment level, the
data is aggregated to provide a Total Company perspective. The AOI’s 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 Blaine and Lincoln
Counties.
• The Idaho Falls Lateral Segment, consisting of the Core Market Customers in Bingham,
Bonneville, Fremont, Jefferson, and Madison Counties.
• The Central Ada County Lateral Segment (“Central Ada”) consisting of the area of Ada County
between Chinden Boulevard and Victory Road, north to south, and between Maple Grove Road
and Black Cat Road, east to west.
• The “North of State Street” Lateral Segment, (“State Street”) consisting of the area of Ada
County north of the Boise River, bound on the west by Kingsbury Road west of Star, and bound
on the east by State Highway 21.
• The All Other Customers Segment, consisting of the Core Market Customers in Ada County not
included in the State Street and Central Ada segments, Bannock, Bear Lake, Caribou, Cassia,
Elmore, Gem, Gooding, Jerome, Minidoka, Owyhee, Payette, Power, Twin Falls, and Washington
Counties
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 14 of 111
RESIDENTIAL AND COMMERCIAL CUSTOMER GROWTH
FORECAST
This section of the Intermountain Gas Company’s Integrated Resource Plan describes and summarizes
the residential and commercial customer growth forecast for the years 2017 through 2021. This
forecast provides the anticipated magnitude and direction of IGC’s residential and small customer
growth by the IGC Distribution System Segments for IGC’s current service territory. Customer growth is
the primary driving factor in IGC’s five-year demand forecast contained within IGC’s IRP.
IGC’s customer growth forecast includes three (3) key components:
1. Residential New Construction Customers,
2. Residential Customers who convert to natural gas from an alternative fuel, and
3. Small Commercial Customers
To calculate the number of customers added each year, the annual change in households for each
county in the IGC Service Territory is determined using the Idaho Economics Winter 2016 Economic
Forecast for the State of Idaho by John S. Church (“’16 Forecast”), dated February 2016. 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 is 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.
To accurately estimate growth for the State Street segment, which 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 current COMPASS household totals
by Traffic Analysis Zones (TAZ) for all of Ada County, the percentage of households by TAZ in the State
Street segment was compared to the overall TAZ total for Ada County. This was calculated to be 33%.
This was used as the base for estimating the forecast growth in the State Street segment.
The Central Ada segment sits entirely in Ada County. A similar methodology to that described above for
the State Street segment was used to derive the percentage of overall Ada County growth forecast for
the State Street segment. This was calculated to be 23%.
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.
With the continued resurgence in the housing market, IGC growth projections are up considerably,
when compared to the 2014 IRP. The ‘16 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.
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 15 of 111
The following graph depicts the relationship, or shape, of customer additions by segment:
The ’16 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.
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 16 of 111
The following graph shows the difference in base case annual additional customers between the 2014
and 2016 IRP forecast years common to both studies:
As indicated, the economic recovery, and its resulting positive impact on housing and
business growth has resulted in a much increased IGC customer growth forecast in the
years common to the 2014 and 2016 IRP’s.
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 17 of 111
The following table shows the results from the 5-year customer growth model for each scenario for the
total customers at each year-end, and the annual additional or incremental, customers:
TOTAL CUSTOMERS ANNUAL ADDITIONAL CUSTOMERS
Low Growth
Baseline
High Growth
Range as a %
Of Base Case
95% - 99%
100% - 100%
101% - 107%
Average as a %
of Base Case
97%
100%
104%
Range as a %
Of Base Case
53% - 56%
100% - 100%
150% - 157%
Average as a %
of Base Case %
56%
100%
156%
Low Growth
Baseline
High Growth
Range
(2017 – 2021)
351,547 – 373,751
355,342 – 394,710
360,776 – 421,773
Average
362,749
375,034
391,389
Range
(2017 – 2021)
5,000 – 5,110
9,000 – 9,680
14,135 – 14,540
Average
5,419
9,596
14,930
The following sections explore, more fully, the different components of the customer forecast, including
the ‘16 Forecast, market penetration and conversion rates, and small commercial growth.
HOUSEHOLD PROJECTIONS / CHURCH FORECAST
The Idaho Economics Winter 2016 Economic Forecast for the State of Idaho by John S. Church (’16
Forecast), provides county by county projections of output, employment and wage data for 21 industry
categories for the State of Idaho, as well as a population and household forecast. This simultaneous
equation model uses personal income and employment by industry as the main economic drivers of the
forecast. This model uses forecasts of national inputs and demands for those sectors of the Idaho
economy having a national or international exposure. Industries that do not have as large a national
profile, and are thus serving local communities and demands are considered secondary industries. Local
economic factors, rather than the national economy determine demand for these products.
The ’16 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 ‘16 Forecast provides three scenarios: (1) baseline, (2) high growth, and (3)
low growth. The baseline scenario assumes a normal amount of economic fluctuation, a normal business
cycle. This becomes the standard against which changes in customer growth, as affected by the low and
high growth scenarios can be measured.
The Base Case Economic Growth Scenario
In the Base Case Scenario of the ‘16 Forecast, it is projected that Idaho will continue to be an attractive
environment for population and household growth. In the decade of the 1990s Idaho's population
increased at an annual average rate of 2.5% per year.
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 18 of 111
The national recession brought a significant slowdown in Idaho's job growth during the 2000 to 2010
period and a decline in the rate of population growth - slowing to an annual average rate of 1.9% per
year over the decade. Nevertheless, that rate of population growth was higher than Idaho's annual
average rate of natural population growth (births minus deaths) of nearly 1.0% per year, indicating that
Idaho continued to attract an in-migration of population even during tough economic times.
In the 2015 to 2040 twenty-five-year forecast period it is anticipated that Idaho's population will
increase by 701,150 reaching a total population of 2,360,000 by the year 2040 -- an annual average pace
of 1.4 percent per year over the twenty-five-year period. The number of households in the state is
expected to increase at a slightly faster pace of 1.8 percent per year over the 2015 to 2040 period
adding nearly 344,300 additional households statewide.
Ada and Canyon Counties are projected to capture the lion's share of the state's future population
growth over the 2015 to 2040 forecast period. Ada County is projected see a population increase of
435,000 (196,100 households) in the 2015 to 2040 period. Canyon County will take up 2nd place
statewide, with a projected absolute population gain of 188,000 (75,800 increase in the number of
households). In Eastern Idaho, Bonneville, Madison, Bannock, and Jefferson counties are expected to
see increases in population of 40,700, 30,100, 20,300, and 16,000, respectively, over the 2015 to 2040
forecast period.
In the Base Case Scenario of ‘16 Forecast, it is assumed that Idaho will continue to be an attractive
environment for the in-migration of new businesses. Idaho's industries regain some economic traction,
and continue to expand in the future. Therefore, despite the employment losses that the State
experienced in the 2008 economic downturn Idaho’s industries regain economic traction and continue
to expand in the future.
Total Non-Agricultural employment in the state is projected to increase by approximately 264,000 over
the 2015 to 2040 period; an annual average increase of 1.3% per year. During those twenty-five years
Ada and Canyon counties are projected to account for 60.1 percent of the total non-ag employment
gains statewide. Again, Ada and Canyon counties are projected to capture the lion's share of job growth
over the 30-year period - 189,200 jobs or 61.9% of the projected non-ag employment gains statewide.
The counties along the Idaho Falls Lateral (Bannock, Bingham, Bonneville, Butte, Fremont, Jefferson,
Madison, and Power) are projected to see non-ag employment increase at an annual average rate of
1.15 percent per year over the 2015 to 2040 period - an absolute increase of 44,300 jobs.
In South Central Idaho, (Blaine, Camas, Cassia, Gooding, Jerome, Lincoln, Minidoka, and Twin Falls
counties) total non-agricultural employment is projected to increase by nearly 21,200 jobs, an annual
average pace of 0.9 percent per year, over the 2015 to 2040 forecast period.
In contrast to previous economic forecasts, the manufacturing sector will not be the driver of economic
growth in the state. From 2000 to 2010, manufacturing employment in the state decreased by 17,200
jobs. In the five years since 2010 Idaho regained nearly 8,000 of those lost manufacturing jobs. However,
in the longer-term manufacturing employment in the state is projected to only increase by a modest
1,800 jobs over the 2015 to 2040 period - an annual average gain of 0.12% per year.
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Employment in the Transportation, Trade, and Utilities industries is projected to increase by nearly
19,900 jobs over the 2015 to 2040 forecast period - an annual increase of 0.55% per year.
Over the 2015 to 2040 forecast period Ada and Canyon counties will capture 16,500 of the
Transportation, Trade, and Utilities jobs in the state -- 83.0% of the projected job gains statewide. The
counties along the Idaho Falls Lateral are projected to see gains of 2,500 jobs in the Transportation,
Trade, and Utilities industries -- 13% of the projected statewide gains in these industries.
Over the 2015 to 2040 forecast period, the combined Service industries are projected to be the sectors
that will add the greatest amount of jobs at over 160,000.
Even with the tight fiscal conditions that came with the last recession, employment in the Government
sector of the Idaho economy increased by nearly 9,700 during the 2000 to 2010 period. The ’16 Forecast
projects that government employment statewide will increase by another 44,900 over the 2015 to 2040
period.
Generally, the bulk of the increase in government employment will be in the state and local government
area, and will largely be associated with the need for additional local government employees to provide
basic services to a growing population in the state.
It is again projected that Ada and Canyon Counties will capture the majority (21,600 jobs) of the
projected government job gains statewide over the 2015 to 2040 period.
The Base Case ‘16 Forecast for the State of Idaho and its 44 counties is for a more optimistic economic
outlook compared to that forecast in the 2014 Church Forecast (‘14 Forecast). As Idaho’s economy
recovers and grows, employment numbers are expected to post a slightly stronger growth rate through
the IRP period.
The High and Low Economic Growth Scenarios
The High-Growth and Low-Growth Scenarios of the ‘16 Forecast present alternative views of the
economic future of Idaho and its 44 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 1,899,760 in the year 2021 versus a Base Scenario Idaho
population forecast of 1,812,020 in the same year. The High Growth scenario average annual compound
rate of population growth from 2015 to 2040 is 1.71% per year.
Alternatively, the Low Growth Scenario of the ‘16 Forecast presents a slower economic outlook for the
Idaho economy. In the Low Growth Scenario, Idaho’s 2021 population is projected to reach the much
lower level of 1,672,920, exhibiting an annual average compound growth rate of 0.9% per year from
2015 to 2040.
An examination of the possible economic and demographic events that could produce the economic and
population growth projected in the High and Low Growth Scenarios is outlined below:
In the High Case Scenario, it is projected that stronger employment gains statewide will be a magnet for
a stronger rate of in-migration to the state. It is assumed that Idaho will be a modestly more attractive
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environment for manufacturing firms. Therefore, Idaho's manufacturing industries are expected to add
an additional 2,600 jobs in manufacturing over the 2015 to 2040 forecast period when compared to the
Base Scenario Forecast.
Transportation, Trade, and Utilities employment in the High Case Scenario is projected to be nearly
10,000 jobs (6.5%) greater by the year 2040 than in the Base Case Scenario. The High Case Scenario
increases in Transportation Industry employment are expected to occur in Idaho's air transportation
sector. Growth in air transportation employment in Boise will accelerate, and that a long-rumored
regional air-freight hub will be established at the Bose Air Terminal. In addition, a new airport for Wood
River Valley will be completed. This new, larger, and safer, airport facility will attract increased air
transportation activity not only directly to the Wood River Valley, but also indirectly with connecting
flights to Boise. In addition, the Communications and Utilities sectors are expected to see higher levels
of employment in the High Scenario. In both the Communications and Utilities industries a large portion
of this projected increase in employment is in reaction to faster population and household growth in the
State.
However, another component of this projected higher level of employment is the assumed continuation
of the growth in the Communications industry’s “call center" facilities in Idaho (T-Mobile, and others)
and the continued expansion of independent electric power production facilities, including wind farms.
Trade industry employment in the High Scenario forecast is projected to be nearly 7,000 jobs (6.2%) jobs
greater by the year 2040 than in the Base Scenario.
Service industry employment in the High Scenario forecast is projected to be even more robust than in
the already strong outlook found in the Base Scenario forecast. In the High Scenario forecast the outlook
for employment in the Service industries is projected to be nearly 24.700 jobs (8.0%) greater than the
Base Scenario outlook by the year 2020, and 110,600 jobs (30.0%) higher than the Base Scenario by the
year 2040. Again, a large portion of this difference is due to the higher levels of population and
household growth anticipated in the High Case Scenario. Hotel and motel accommodations and
activities are also classified in the Service industry category. The High Scenario forecast assumes that
tourism related or recreational travel in Idaho increases and as a result employment in the lodging and
recreation sectors also increase. In the High Scenario, economic forecast the shuttered Tamarack Resort
is assumed to recover from its current state of closure and will flourish under a new future ownership.
The High Scenario utilizes a view of business migration in the Western US that was relevant prior to the
2008 national recession and as the US economy has recovered the same pressures for business
migration are becoming more and more relevant again today. The Service industry outlook in the High
Scenario forecast assumes that, there is a portion, roughly one-half, of the projected higher level of
service industry employment that is caused by the relocation of firms new to Idaho. The Federal
Reserve Bank of San Francisco speculates that a portion of the strong economic growth prior to the last
recession that was experienced in Arizona, Nevada, New Mexico, Oregon, Utah and Idaho was due to an
outmigration of population and businesses from California. Their studies have shown that many small
California firms have reached a realization that the cost of doing business in California has become too
great for them to remain competitive. Therefore, an increasing number of these firms made decisions
to relocate close to, but outside of, California. Hence, the very rapid growth that occurred prior to the
national recession in Nevada, Arizona, and to a lesser extent Southern Oregon. New Mexico, Utah, and
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Idaho captured only a small portion of that exodus. The High Scenario Forecast assumes that this trend
continues and that Idaho, over time, will capture a larger share of those relocation decisions.
Federal Government employment in the High Scenario forecast is assumed to be identical to the outlook
for federal employment in Base Scenario outlook. It is assumed in the High Case Scenario that the
number of assigned personnel at Mountain Home Air Force Base will be about 2,000 higher than under
the Base Scenario Forecast. The number of military personnel does not normally show up in the state's
total employment figures.
It is further assumed that Mining industry employment in North Idaho's silver mines the High Scenario
Forecast will be nearly 700 higher than the in the Base Scenario forecast. In general, Construction,
Natural Resources, and Mining industry employment in the High Scenario is expected to be nearly 1,800
(3.0 percent) higher by the year 2040 than in the Base Case. With the exception of the assumed gains in
the Mining industry mentioned above this higher level of employment is in the Construction industry
and is due to the projected higher level of population and population growth.
In the Low Case Scenario forecast of population and number of households in Idaho is 13% lower than
the Base Case figures by the year 2040. This represents nearly 297,800 fewer people in the State by the
year 2040 and nearly 128,600 fewer households. In the Low Case Scenario, it is projected that slower
overall employment gains statewide will cause Idaho to be less attractive to a job-seeking population
that would otherwise migrate to Idaho.
Idaho's Manufacturing employment in Low Scenario forecast does not significantly recover from the
2008 national recession over the 2015 - 2040 forecast period.
In the Low Scenario forecast the State's loss of jobs in the Food Processing industry accelerates and
nearly 1,300 additional jobs are lost over the 2015 to 2040 forecast period. The potato processing plants
in Southern Idaho would experience the bulk of these job losses. It is assumed in the Low Scenario that
the JR Simplot plant in Caldwell would shed over 1,000 jobs by the year 2020. It is further assumed in
the Low Scenario that the sugar processing plants in Southern Idaho would also feel increased
pressure from competition and would find it necessary to close one of the sugar processing plants in
either Nampa, Paul, or Twin Falls, Idaho. The dairy industry and its associated food processing plants
would reach a point where no further capacity could be added due to increased population and
environmental pressures.
Employment losses in Idaho's Lumber and Wood Products manufacturing industry are assumed to
accelerate in the Low Scenario. In this scenario the brunt of these additional losses would be felt in
those portions of the wood products industry that could be increasingly vulnerable to low cost foreign
produced products - the Wood Grain Molding plants in Fruitland and Nampa, Idaho.
Idaho's Electronics and Machinery manufacturing industries would experience further job losses over
the forecast period. Employment in Stone, Clay, and Glass Products and Fabricated Metal Products
manufacturing are both projected to be at lower levels of total employment than in the Base Scenario.
In general, in the Low Scenario forecast, Manufacturing industry employment in the year 2040 is
projected to be nearly 5,800 jobs (10.0 percent) lower than in the Base Scenario forecast.
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Transportation, Trade, and Utilities employment in the Low Scenario is projected to have nearly 4,200
fewer jobs (a change of -2.8 percent) by the year 2040 than in the Base Scenario forecast. It is assumed
that the lower overall economic growth inherent in the Low Scenario produces lower levels of demand
for transportation services and for the buying opportunities of additional retail stores. Also, inherent in
the Low Scenario forecast is the assumption that there will be closure or downsizing of some of the
State's food processing facilities, which all require significant amounts of truck transportation.
Wholesale and Retail Trade industry employment in the Low Scenario forecast is projected to be nearly
2,100 jobs lower than the Base Scenario forecast in the year 2040. The difference in Trade industry
employment is due to the lower levels of population and household growth found in the Low Scenario.
Idaho's Transportation, Trade, and Utilities industry employment in the Low Scenario is projected to be
4,200 jobs (3.0 percent) below Base Scenario forecast levels in the year 2040. Nevertheless, Idaho's
Transportation, Trade, and Utilities industry employment in the Low Scenario is expected to increase by
nearly 15,000 over the 2015 to 2040 forecast period.
The Low Scenario forecast of statewide employment in the Finance, Insurance, and Real Estate sector is
about 5,300 (14.0 percent) lower than in the Base Scenario Forecast by the year 2040. Again, the
difference is largely due to the lower levels of population and household growth found in the Low Case
Scenario.
The outlook for Service industry employment in the Low Scenario forecast assumes that employment
growth in the Service sector slows proportionate to the projected slower growth in population and
households statewide. Further, it is assumed that Idaho is less attractive to those Service industry firms
from outside of Idaho that may have considered relocating all or a portion of their activities to Idaho.
Idaho's competitive position for attractive new business is degraded and the nearby states of Utah,
Oregon, and Nevada capture a larger proportion of firms making relocation and expansion decisions.
Future Government employment in the Low Scenario is projected to be 11.0 percent (16,100 jobs) lower
than the Base Scenario forecast by the year 2040. As previously mentioned for other industries the
reason for projected lower levels of Government employment in the Low Scenario forecast are the
slower rates of population and household growth in the Low Case. It is assumed in the Low Scenario that
the number of assigned military personnel at Mountain Home Airforce Base will be maintain at levels
that are similar to those at present time.
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The following graph shows the difference in base case annual additional households between the 2014
and 2016 IRP forecast years common to both studies:
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The following graph shows the difference in base case annual additional households between the 2014
and 2016 IRP forecast years common to both studies:
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The following graph shows the difference in base case total households between the 2014 and 2016 IRP
forecast years common to both studies:
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MARKET SHARE RATES
IGC utilizes market penetration rates that vary across the service territory. These regional penetration
rates are applied to the IGC service-territory counties within the three specific regions: west, central,
and east. These penetration rates are the ratio of IGC’s additional residential new construction
customers to the total building permits in those regions. The forecast additional households, per the
Church 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 IGC 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. These rates are derived month by month.
The market penetration rates used in the customer forecasting varied somewhat when going into the
future out of anticipated market share gains in the Central and Eastern regions. Those for the West
remained relatively static through the forecast period, since they are already near 100%. The same set
of market penetration rates was used in the baseline, high growth, and low growth scenarios.
MARKET PENETRATION RATES
Western Region
FY17 FY18 FY19 FY20 FY21
98% 98% 98% 98% 98%
Central Division 89% 89% 89% 89% 89%
Eastern Region 74% 74% 74% 74% 74%
The following graph illustrates the relationship between the three economic scenarios for the annual
residential new construction growth forecast for 2017 – 2021:
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The following graph shows the difference in base case residential new construction customer growth
between the ‘14 and ‘16 IRP forecast years common to both studies:
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CONVERSIONS
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
customer additions which will be conversions.
REGIONAL CONVERSION RATES
Western Region
FY17 FY18 FY19 FY20 FY21
Base Case 9% 9% 9% 9% 9%
High Growth 9% 9% 9% 9% 9%
Low Growth 9% 9% 9% 9% 9%
Central Region
Base Case 21% 21% 21% 21% 21%
High Growth 21% 21% 21% 21% 21%
Low Growth 21% 21% 21% 21% 21%
Eastern Division
Base Case 23% 23% 23% 23% 23%
High Growth 23% 23% 23% 23% 23%
Low Growth 23% 23% 23% 23% 23%
The following graph illustrates the relationship between the three economic scenarios for the annual
residential conversion growth forecast for 2017 – 2021:
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The following graph shows the difference in base case residential conversion customer growth between
the ‘14 and ‘16 IRP forecast years common to both studies:
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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 5.80%, 10.22%, and 10.15%, respectively. Therefore, regional ratios of 6% for the West, and
10% for Central, and 10% for the 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 2017 – 2021:
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The following graph shows the difference in base case commercial customer growth between the ‘14
and ‘16 IRP forecast years common to both studies:
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HEATING DEGREE DAYS AND DESIGN WEATHER
Intermountain’s demand forecast captures the influence weather has on system loads by using Heating
Degree Days (HDD’s) as an input. 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
AOIs are also addressed specifically by this IRP. Those segments are assigned unique degree days as
discussed in further detail below.
Normal Degree-Days
A Normal Degree Day is calculated based on historical data, and represents the weather that could
reasonably be expected to occur on a given day. The Normal Degree Day that Intermountain utilizes in
the IRP is computed based on weather data for the thirty years ended December 2015. The HDD65 for
January 1st for each year of the thirty year period is averaged to come up with the average HDD65 for
the thirty year period for January 1st. This method is used for each day of the year to arrive at a year’s
worth of Normal Degree Days.
Design Degree-Days
Design Degree Days are 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 period of record from NOAA. That review revealed Intermountain'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.
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Peak Heating Degree Day Calculation
Intermountain also engaged the services of Dr. Russell Qualls, Idaho State Climatologist, to perform a
review of the methodology used to calculate design weather, and to provide suggestions to enhance the
design weather planning. One crucial area that Dr. Qualls 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.
To develop the peak heating degree day, or coldest day of the design year, Dr. Qualls fitted probability
distributions to as much of the entire period of record from seven weather station locations (Caldwell,
Boise, Hailey, Twin Falls, Pocatello, Idaho Falls and Rexburg) as was deemed reliable. From these
distributions he calculated monthly and annual minimum daily average temperatures for each weather
location, corresponding to different values of exceedance probability. Two probability distributions
were fitted, a Normal Distribution, and a Pearson Type III (P3) distribution. Dr. Qualls suggested it is
more appropriate for Intermountain to use the P3 distribution as it is more conservative from a risk
reduction standpoint.
According to Dr. Qualls, “selecting design temperatures from the values generated by these probability
distributions is preferable over using the coldest observed daily average temperature, because
exceedance probabilities corresponding to values obtained from the probability distributions are known.
This enables IGC to choose a design temperature, from among a range of values, which corresponds to
an exceedance probability that IGC considers appropriate for the intended use”.
Intermountain used Dr. Qualls’ exceedance probability 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 a 79 degree day, would be appropriate to
use for our design weather model. For modeling purposes, this 79 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, the weather profile for
December 1985 replaced the January 1985 data in the base design year. For planning purposes, the
aforementioned peak day event was placed on January 15th.
To model the days surrounding the peak event, Dr. Qualls suggested calculating a 5-day moving average
of the temperatures for the past thirty year period to select the 5 coldest consecutive days from the
period. December 1990 contained this cold data. The coldest day of the peak month (December 1985)
was replaced with the 79 degree day peak day. Then, the day prior and three days following the peak
day, were replaced with the 4 cold days surrounding the December 1990 peak day.
While taking a closer look at the heating degree days used for the Load Demand Curves (“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
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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 Table 1 below). This curve provides a robust projection of the extreme
temperatures that can occur in Intermountain’s service territory.
Table 1
Degree Day Graph
The resulting Normal, Base Year, and Design Year degree days by month are outlined in the following
Table 2:
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Table 2
Degree Days by Month
Degree Days by Month
Weighted Normal
(30 Year Rolling)
Actual Heating Year
1985 Design Year
October 416 599 599
November 794 823 823
December 1,089 1,316 1,316
January 1,105 1,433 1,690
February 852 1,134 1,134
March 675 973 973
April 461 425 425
May 244 242 242
June 66 68 68
July 2 0 0
August 7 34 34
September 107 292 292
Total 5,819 7,339 7,596
Area Specific Degree Days
In the 2012 IRP, Intermountain noted unique characteristics of certain areas of interest on 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 temperatures in these areas can be quite different from each other and from the Total Company.
For example, the temperatures experienced in Idaho Falls or Sun Valley can be significantly different
from those experienced in Boise or Pocatello. Intermountain continues to work on improving its
capability to uniquely forecast loads for these distinct areas. A key driver to these area specific load
forecasts is area specific heating degree days.
Intermountain has developed Normal and Design Degree Days for each of the areas of interest. The
methods employed to calculate the Normal and Design Degree Days for each AOI mirrors the methods
used to calculate Total Company Normal and Design Degree Days.
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USAGE PER CUSTOMER
The IRP planning process utilizes customer usage as an essential calculation to translate current and
future customer counts into estimated demands on the distribution system and total demand for gas
supply and interstate transportation planning. The calculated usage per customer is dependent upon
weather and geographic location.
Methodology
Intermountain Gas now utilizes a Customer Management Module (CMM) software product, provided by
DNV GL as part of their Synergi Gas product line, to analyze natural gas usage data and to predict usage
patterns on the individual customer level. DNV GL operates in over 100 countries while specializing in
the maritime, oil, gas and energy industries. Their array of pipeline software has been a powerful
engineering tool within the United States for decades, used by natural gas companies such as Avista,
PG&E, Questar and Williams. The CMM product branch is used in correlation with Synergi Gas, a
hydraulic modeling software program discussed in the Distribution System Modeling section of this IRP.
The first step in operating CMM is extensive data gathering from the company’s Customer Information
System (CIS). CIS houses historical monthly meter read data for each of Intermountain’s customers,
along with daily historical weather and the physical location of each customer. The weather data is
associated with each customer based on location, and then related to each customer’s monthly meter
read according to the date range of usage.
After the correct weather information has been correlated to each meter read, a base load and weather
dependent load are calculated for each customer through regression analysis over the historical usage
period. DNVGL states they use a “standard least-squares-fit on ordered pairs of usage and degree day”
regression “with additional proprietary modifications”. The final result is a customer specific base load
that is weather independent, and a heat load that is multiplied by a weather variable, to create a custom
regression equation.
Should insufficient data exist to adequately predict a customer’s usage factors then CMM will perform
factor substitution. Typically the average usage of customers in the same geographical location and in
the same customer rate class can be used to substitute load factor data for a customer who lacks
sufficient information for independent analysis.
Time Series
The first step in analyzing data through CMM was to determine the appropriate time period to include in
the study. A study by the American Gas Association found that average natural gas usage per customer
is on the decline. The average U.S. home using natural gas uses 40% less today than they did 4 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
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people have installed them in older homes as a way to reduce their energy expense (see “The Efficient
and Direct Use of Natural Gas”, beginning at page 74).
All of these conservation influences began impacting usage in the early 1990’s. Since over 67% 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.
With all the structural shifts in historical data, and the significantly increased quantity of data utilized for
regression, Intermountain used a time series beginning with the summer of 2011 through the summer
of 2015 to develop the usage per customer equations. The selected time series is aligned with the
recommended time study from DNVGL.
Usage per Customer by Geographic Area
In a service territory as geographically and economically diverse as Intermountain Gas Company’s, we
recognize that there could be significant differences in the way customers use natural gas based upon
their location on Intermountain’s system. Being sensitive to areas that may require capital
improvements to keep pace with demand growth, Intermountain separated customers based on their
geographic area as related to area of interest and then determined specific usages per customer. The
areas of interest (AOI) that Intermountain studied for possible usage per customer refinements
included; Canyon County, Central Ada County, State Street Lateral, Sun Valley Lateral, and Idaho Falls
Lateral.
In order to refine usage per customer to an AOI, customer address’ were used to create groups by town,
and towns were combined to their related AOI. Central Ada and State Street AOI’s share towns in their
respective territories, so a combined geographic area was created to calculate their shared usage per
customer. Towns on the Sun Valley Lateral were combined to calculate a single usage per customer, but
for Synergi Gas modeling purposes the usage per customer was represented separately for each town
due to the range of usages and geographic sensitivity along the lateral. The same Sun Valley Lateral
methodology was applied to the Idaho Falls Lateral Synergi model.
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LARGE VOLUME CUSTOMER FORECAST
Introduction
On average, the Large Volume (LV) customers account for approximately 50% of Intermountain’s annual
throughput. Approximately 98% of the Large Volume throughput reflects distribution system-only
transportation tariffs where the customer-owned natural gas supplies are delivered to Intermountain’s
Citygate stations for ultimate redelivery to the customers’ facilities.
Because the LV customers’ volumes account for a such large part of Intermountain’s overall throughput,
the method of forecasting is an important part of the IRP. However, since these customers are far less
weather sensitive than the core market customers and they are relatively few, forecasting their volumes
using standard regression techniques based on weather does not provide acceptable results. Therefore,
Intermountain has developed and utilizes an alternate method of sales forecasting based on historical
usage, economic trends and input from these Large Volume customers.
Method of Forecasting
Intermountain started the LV forecast by utilizing recent actual historical usage as the base. Each
customer’s monthly usage for the most recent 3 years was assessed and a representative twelve-month
period was chosen as the starting point although more weight was applied to the most recent twelve
month period.
To this base, the Company adjusted monthly therms in the out years based information received from
the customers pursuant to the survey form sent out to each customer January 2016 (see page 44 for an
example). As shown below, the survey form included a cover letter explaining the intent and use of the
requested information with the assurance that all responses would remain confidential). The surveys
provided each customer’s historical peak day and monthly usage for the two years ending 2015.
The historical information was designed to give management, engineers, and/or operations personnel a
quick glance of recent usage patterns to assist them with their projections for future natural gas
requirements. In specific, the survey requested projections of changes in natural gas consumptions
changes related to plant expansion, equipment modification or replacement, anticipated changes in
product demand and production cycles through 2021.
Finally, each customer was provided an opportunity to give recommendations for additional service
options or other feedback. The analysis of the returned surveys was completed in the March 2016.
Forecast Scenarios
For the IRP, Intermountain prepared three separate LV monthly gas consumption forecasts (Base Case,
High Growth and Low Growth). The Base Case forecast started with the data as described above and
was combined expected economic trends to develop the five-year Base Case forecast. Other available
data, including inquiries to/from economic development organizations and general economic patterns
was utilized to develop the High Growth and Low Growth scenarios. For ease of analysis, the 120
existing and up to 10 projected new customers (per the High Growth scenario) were combined into six
(6) homogeneous market segments:
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2017 Customers-
• 16 potato processors
• 36 other food processors including sugar, milk, beef, and seed companies
• 3 chemical and fertilizer companies
• 25 light manufacturing companies including electronics, paper, and asphalt companies
• 30 schools, hospitals and other weather sensitive customers
• 10 other companies
Firm Contract Demand (MDFQ)
Every LV customer is required to sign a contract to receive service under any LV Tariff. An important
element of the firm contracts is the Maximum Daily Firm Quantity (“MDFQ”) which sets the maximum
amount of daily gas and/or capacity the Company must be prepared to provide a firm LV customer on
any given day. Due to events relative the Company’s general rate case (INT-G-16-02), all LV customers
were provided an Open Season during November 2016 to allow them to restate their contractual MDFQ.
The Open Season resulting in a 12% overall decrease in MDFQ or approximately 200,000 therms/day.
These customer elections are used in this IRP.
Some of the largest customers predict that while their annual and/or off-peak day requirements could
grow their peak day requirement will likely not increase. This is due in part to their use of extended work
schedules by adding additional daily shifts or adding production in weeks or months not previously
utilized at 100% load factor.
For Optimization modeling purposed, the LV customers’ MDFQ’s are summarized by AOI in order to
model LV firm demands in each Area of Interest. Those peak day figures help to analyze the need for
potential future upgrades to the existing laterals serving each community.
Load Profive vs MDFQ
Because Intermountain does not provide interstate capacity or gas supply for any of the transportation
customers, the IRP optimization model does not utilize the customers’ monthly or daily load profiles but
instead models industrial loads based on aggregated LV MDFQ. These MDFQ’s are loaded directly into
the optimization model for the purpose of “reserving” the contractual distribution capacity that each
customer may access on any day of the year. The MDFQ figures also reflect the amount of zero cost gas
supply that each transport rate class will provide to the system on every given day of the year. That
assumption allows the model to recognize that gas supply and/or interstate capacity requirements for
the transport customers are not provided by Intermountain.
Energy Efficiency
Through discussions with the customers and the information provided via the surveys, it is apparent that
maximizing plant efficiency by optimizing production volumes while using the least amount of energy is
a very high priority of the owners, operators, and managers of these LV facilities. Over a decade ago
Intermountain developed a SCADA technology combined with remote radio telemetry technology to
gather, transmit and store a customer’s natural gas usage.
This technology provides customer access to therm use data and Intermountain deployed a website that
customers could access at their convenience. The website provides near real-time monthly, daily and
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hourly historical natural gas usage to customers where SCADA is installed. This usage data can be viewed
and/or downloaded by plant personnel at their convenience via the internet. Intermountain believes
this information continues to help plant managers with their energy conservation and efficiency efforts.
The company recently redesigned the website to enhance customer flexibility and system stability.
General Assumptions
All current customers were assumed to remain on their current tariff and all forecast scenarios used the
2017 operating budget as a starting point. While Intermountain recognizes that T-5 customers may be
required to migrate to T-4 due to case INT-G-16-02, any such change will affect the optimization
modeling.
The IRP also calculated LV therm use and MDFQ by AOI so that each geographic area of concern can be
accurately modeled. If LV customers request future increases to their MDFQ, Intermountain will test
those increases against system availability and only allow increases where it is available. Customer that
request increased MDFQ in areas that do not have available capacity will be required to invest in new
facilities.
Base Case Scenario
The Base Case was compiled using historical usage and surveys with adjustments made to reflect known
or probable changes of existing customers. The projected annual usage in Base Case forecast increased
by 29.1 million therms (or 9%) over the Five Year.
A. The Potato Processors group is forecast to be relatively flat over the five year period. Demand
for potato products is flat, and the supply is good. No new plants are on the drawing boards in
the near future. Most of the plants in this group are looking for ways to conserve resources
while maximizing production, thus lowering the overall cost of product unit.
B. The Other Food Processors group is also 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 and production increases in the forecast. In their forecasts, the managers of
these plants assume imported fertilizers will not, at least in the foreseeable future, affect their
operations.
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D. The Manufacturing group is expected to grow slightly. Some proposed plant expansions might
increase manufacturing further.
E. The Institutional group is projected to grow at 0.55% a year, due mainly to fuel switching to gas
at BYU Idaho.
F. The usage in the Other group is projected to be relatively flat over the period.
High Growth Forecast Summary
The High Growth – or most optimistic – forecast figures incorporate usage data directly from the survey
with adjustments. The High case forecast starts out approximately 7.5% above the Base Case numbers.
The increase from the 2015 annual usage estimate of 265,033,000 therms is projected to increase
5,765,000 therms, or approximately 2.2% over the five year period. The following table summarizes the
changes over this period:
A. Potato production is up from the 2012 IRP projections, and the future looks steady for the
potato industry. This scenario shows the processors flat, although at record high levels. Near-
record potato crop in 2011 is a two edge sword—great quality and yield but also higher prices.
Natural gas prices should stay steady and low which would keep the plants using gas rather than
oil.
B. Other Food Processors are projected to be flat across the reporting period again at record high
levels. The addition of Chobani 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 XL Beef in Nampa is a
dampener.
C. The Chemical/Fertilizer group is projected to increase in size with the addition of a new plant.
The three existing plants, plus the forecast additional facility in this group project steady
production and usage at high levels.
D. The Manufacturing group is projected to have a slight increase over the period with the addition
of two new manufacturing plants – one in the high tech industry, and one asphalt producer.
E. The Institutional group, which is made up mostly of schools and hospitals, is projected by the
survey to grow with increased usage at a few.
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F. The Other group is projected to grow slightly, with some increased usage at a greenhouse, and
an addition of a new user. Usage will be relatively flat across the reporting period in the high
case.
Low Growth Scenario
The projected usage for this scenario is based upon the assumption that the agricultural economy will
be flat with very little growth in sales and production. It is also assumed that natural gas prices will be
relatively flat, and remain reasonably competitive. With those assumptions, no downturns are
projected. Very little growth is forecast in Potato Processing. The Low Growth Scenario projections
start 2% below the Base Case in 2013 with overall usage increasing a projected 1% over the period, as
shown below.
A. The price of natural gas was assumed to be competitive against the delivered price of oil. Potato
consumption is assumed to remain at current levels. This group, as a whole, looks at any way
possible to conserve energy and make its plants more efficient.
B. In the Other Food Processor group is expected to remain steady. Existing facilities will remain
flat.
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 0.7% although starting
1.1% below the base case, assuming that no additional “High Tech” production occurs and no
unforeseen state or federal highway projects begin.
E. The growth projection for the Institutional group in the low growth forecast is attributed to the
known expansion of universities, schools, and hospitals.
F. Facilities in the Other group are projected to increase mainly due to some increased usage at a
greenhouse facility.
Large Volume Low Growth Scenario by Market Segment
(Thousands of Therms)
2017
2018
2019
2020
2021
Compound Rate
of Growth
Potato Processors 102,951 100,388 99,388 99,388 99,388 -0.9%
Other Food, Dairy & Ag 146,567 150,966 151,320 155,220 155,220 1.4%
Chemical & Fertilizer 31,628 32,200 32,200 37,200 42,200 7.5%
Manufacturers 20,292 22,033 22,725 22,475 22,448 2.6%
Institutions 22,088 22,402 22,490 22,735 22,775 0.8%
Other 18,403 18,661 18,666 18,871 19,076 0.9%
Total Base Case 341,929 346,650 346,789 355,889 361,107 1.4%
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LARGE VOLUME CUSTOMER SURVEY – COVER LETTER
Date
Name
Company
Address
Address
Dear:
Intermountain Gas Company values you as a customer and we are committed to meeting your
expectations by providing reliable energy services to your facility. We continue to see steady
growth in natural gas usage from all sectors of our business. That growth coupled with the real
potential for extremely cold winter weather emphasizes the importance of our long-term
planning efforts.
An Order from the Idaho Public Utilities Commission (Commission) requires Intermountain to file
an Integrated Resource Plan (IRP) every two years. The IRP is comprehensive, long-term plan
that gives the Commission the opportunity to assess our forecast including its inputs, underlying
methodologies and conclusions. The process documents our forecasting efforts, encourages
public involvement, and provides assurance to our customers how Intermountain plans to meet
your future energy needs in a prudent manner.
We are now beginning our next IRP process and I am writing to solicit your assistance. In order
for the IRP to be as accurate as possible, it is crucial that we obtain and incorporate your
projected natural gas requirements for the next several years. I have enclosed a survey form
that requests information relative projected changes in your facility’s annual and peak day
natural gas requirements and alternate fuel plans. To provide context, I have included historical
annual and peak day (where available) therm use data for the two most recent years.
I recognize the effort required for you to complete this survey but I assure you that it is important
and we will use it in our IRP. Your data will improve the accuracy of our demand forecast which
will help Intermountain continue to employ the resources necessary to provide our customers
with reliable year-round service. Please return your completed survey, including any comments
or questions you may have, by January 8, 2015. As always, any information you provide will be
strictly confidential, will not be shared with any other entity and will be aggregated with data
from other customers in any public filing.
Should you have any questions or if I can be of assistance to you, please call me at (208) 377-
6118 or (208) 794-4118 or you can email me at dave.swenson@intgas.com.
I thank you in advance,
David Swenson
Manager, Industrial Services
Intermountain Gas Company
Enclosures
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TRADITIONAL SUPPLY-SIDE RESOURCES
Overview
The natural gas marketplace continues to change but Intermountain's commitment to act with integrity
to provide secure, reliable and price-competitive firm natural gas delivery to its customers has not. In
today’s energy environment, Intermountain bears the 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 prolific gas producing regions in North
America. The first, the Western Canadian Sedimentary Basin (WCSB) in Alberta and northeastern British
Columba supplies approximately 70% 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
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 gas from those supply basins to Intermountain’s distribution system. The
Company is also well positioned relating to pipeline capacity as this region has multiple interstate
pipeline options providing ample capacity to transport gas to Intermountain’ s citygates. A basic
discussion of gas supply, storage and interstate capacity resources follow.
Gas Supply Resource Options
Over the past few years, advances in technology have allowed for the discovery and development of
abundant supplies of natural gas within shale plays across the United States and Canada. This shale gas
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revolution has changed the energy landscape in the United States. Natural gas production levels
continue to surpass expectations despite low gas prices and concerns about shale production techniques
(See Chart 1 below).
Chart 1 Source: EIA AEO2016
Projected low prices for natural gas have made it a very attractive fuel for natural gas fired electric
generation as utilities look for replacement for coal-fired generation. Combine this with the industrial
sector’s post-recession recovery as they look to take advantage of low natural gas prices, and the result
is a significant change in demand loads. See Chart 2 below for consumption by sector, 1990-2040.
Chart 2 Source: EIA AEO2016
Improved technologies for finding and producing non-traditional gas supplies have led to huge increases
in gas supplies. Chart 3 below shows that shale gas production is not only replacing declines in other
sources, but is projected to increase total annual production levels through 2040.
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Chart 3 Source: EIA AEO2016 Chart 4 Source: NWGA 2016 Gas Outlook
While natural gas prices continue to exhibit volatility from both a 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 (see Chart 4 above for shifting Demand). Finding equilibrium in the market
has been challenging for all market participants but at the end of the day, the competitive market clearly
works; the challenge is avoiding huge swings that result in either demand destruction or financial
distress in the exploration and production business.
Driven by technological breakthroughs in unconventional gas production, major increases in U.S. natural
gas reserves and production have led to supply growth significantly outgaining forecasts in recent years.
Thus, natural gas producers have sought new and additional sources of demand for the newfound
volumes. One proposed end-use is the exportation of U.S. natural gas in the form of liquefied natural gas
(LNG). While the United States already exports some quantities of natural gas, mostly via pipeline,
current proposals, some of which have already received some level of approval from the federal
government, would substantially increase the volume of LNG exports.
Shale Gas
Shale gas has changed the face of US energy. Today reserve and production forecasts predict ample and
growing gas supplies through 2040 because of shale gas. The fact that shale gas is being produced in the
mid-section of the U.S has displaced production from more traditional supply basins in Canada and the
Gulf Coast. There have been some perceived environmental issues relating to shale production but most
studies indicate that if done properly, shale gas can be produced safely. Customers now enjoy the
lowest prices in years due to the increased production of shale gas.
Per EIA, the portion of U.S. energy consumption supplied by domestic production has been increasing
since 2005, when it was at its historical low point (69%). Since 2005, production of domestic resources,
particularly natural gas and crude oil, have been increasing because of shale gas production.
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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 70% 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. Figure 1 below identifies the shale plays in the lower 48 states.
Figure 1 Source: Energy Information Administration based on data from various published
studies. Updated May 9, 2011.
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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 below in Figure 2.
Figure 2
Production in this province has historically been abundant. In fact, Alberta was believed to have the
largest natural gas reserves in North America, and annually produced 10 times the Pacific Northwest’s
yearly consumption. However, we have seen recent production and reserve declines, and some
forecasts indicate continuing declines in availability of export gas. The decline is a result of producers
not being able to adequately replace the prolific but generally produced reserves in addition to the fact
that 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 has kept Alberta prices strong in comparison to Rockies supplies.
However, Canadian producers are beginning to find and produce its vast regions of unrecovered coal
seam and shale formations, thus reversing a trend of declining production.
Alberta gas supplies typically flow to the eastern U.S. and California where price levels are generally
higher, meaning that Alberta supplies are 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 than Rockies supply as can be seen in
the chart below.
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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 (Enbridge) 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 has forced producers to compete to sell their supplies to markets with firm pipeline
takeaway capacity. Consequently, Rockies supplies have tended to trade at lower prices than the
Canadian or other regional U.S. sources.
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 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 could result in an increase in
the cost of future Rockies supplies.
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 has allowed the Company to maximize the amount of Rockies
supply which has helped to keep the company’s purchased cost of gas low. 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
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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. Long-term the dynamics between Rockies
and Alberta supplies should ensure price competitiveness with one another.
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.
Growth in North American natural gas supplies (see ‘Shale Gas’ above) has decreased discussion about
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. Conversation has now turned to several proposed LNG ports
which are proposing to export LNG to international markets in Asia. Per AEO2016 Reference case, the
United States becomes a net exporter of natural gas in 2018 due in large part to the export of LNG.
Chart 5 below identifies LNG imports by year going back to 1990. A downward trend going back to 2007
is apparent, and in 2015 LNG imports were at their lowest levels since 1995 and trending to net exports.
Chart 5 Source: EIA AEO2016
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 day during the term of the contract and commits the
buyer to take that gas on each day. The only exception would be force majeure events where one or
both parties cannot control external events that make delivery or receipt impossible. Interruptible or
best efforts gas supply typically is bought and sold with the understanding that either party for various
reasons, 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 purchase points Intermountain utilizes
has allowed for more flexibility in the structure of the portfolio. The historical heavy reliance on mostly
longer-term contracts for much of the portfolio has lessened as the Company has found that it can shift
more of its supplies to shorter termed spot or index contracts. Doing so provides increased flexibility 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.
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For example, interruptible supply may be used to supplement summer storage injections because a
failure would not jeopardize any customers and the injection could easily be made up on a subsequent
day. Of course, 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 to participate in the competitive market while avoiding much of the price 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, to provide stable and competitive prices for its
customers.
For optimization purposes, Intermountain obtained three five-year price forecasts for the AECO, Rockies
and Sumas pricing points from three energy companies based on the May 26, 2016 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 very similar to one another. Therefore, the
Company determined that it could reasonably use the average of the forecasts for modeling purposes.
The selected forecast included a monthly base price projection for each of the three purchase points, as
seen in Chart 6 below.
Chart 6
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 daily. As seen in the Load Demand Curve section of this IRP, the steep decline in
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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 clear 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 Williams Norwest Pipeline: one is an underground project
located near Jackson Prairie, WA (“JP”) and the other is a liquefied gas (“LS”) facility located near
Plymouth, WA (See map below Figure 3). Intermountain also leases capacity from Questar Pipeline’s
Clay Basin underground storage field and operates its own LNG facility located in Nampa, ID.
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.
Figure 3 Source: NWGA 2016 Gas Outlook
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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 non-toxic; it is non-corrosive and will only burn when vaporized to a 5-15%
concentration with air. Because of the characteristics of liquid, its natural propensity to boil-off and the
enormous amount of energy stored, LNG is normally stored in man-made steel tanks.
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.
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 so a typical underground injection season is much shorter, maybe only 3-4 months. But the lower
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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 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 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
(Table 1) outlines the Company’s storage resources for this IRP.
Table 1
Storage Statistics
Daily Withdrawal Daily Injection
Facility
Seasonal
Capacity Max Vol
% of 2015
Peak Max Vol 1 # of Days
Redelivery
Capacity
Nampa 580,000 60,000 16% 3,500 166 None
Plymouth 1,475,135 155,175 43% 5,660 193 TF-2
Subtotal Liquid 2,055,135 215,175 59% 9,160
Jackson Prairie 1,092,099 30,337 8% 30,337 36 TF-2
Clay Basin 8.413.500 70,109 19% 70,109 120 TF-1
Subtotal Undgrnd 9,512,599 100,446 27% 100,446
Grand Total 11,567,734 315,621 86% 109,606
1 These figures are based on tariff or contract 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 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 lower.
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
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level of efficiency, economics and security not otherwise achievable. Geographic diversity provides
security should pipeline capacity become constrained in one 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 facilities.
Interstate Pipeline Transportation Capacity
As earlier discussed, Intermountain is dependent upon 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 is the only interstate pipeline which interconnects to
Intermountain’s distribution system, meaning that Intermountain physically receives all gas supply to its
distribution system via “Citygate” taps with Northwest. Table 2 below summarizes the Company’s year-
round capacity on Northwest (TF-1) and its storage specific redelivery capacity (TF-2). Between the
amount of capacity 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 2017 2018 2019 2020 2021
TF-1 Capacity-
Sumas 17,141 17,141 17,141 17,141 17,141
Stanfield 148,670 148,670 148,670 148,670 148,670
Rockies 97,478 97,478 97,478 97,478 97,478
Citygate 18,056 18,056 18,056 18,056 18,056
Total TF-1 281,345 281,345 281,345 281,345 281,345
Storage (TF-2) 185,512 185,512 185,512 185,512 185,512
Max. Citygate Delivery 466,857 466,857 466,857 466,857 466,857
Northwest Pipeline’s facilities essentially run from the Four Corners area north to western Wyoming,
across Southern Idaho to Western Washington. The pipeline then continues up the I-5 corridor where it
interconnects with Spectra Energy (Enbridge), 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 in Wyoming, Utah, Colorado and New Mexico. The major pipelines in the Pacific Northwest,
several of which Northwest Pipeline interconnect with can be seen below (Figure 4).
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Figure 4
Because natural gas must flow along pipelines with finite flow capabilities, demand frequently cannot be
met from a market’s preferred basin. Competition among markets for these preferred gas supplies can
cause capacity bottlenecks and these bottlenecks often result in pricing variations between basins
supplying the same market area. In the short to medium term, producers in constrained basins
invariably must either discount or in some fashion differentiate their product to compete with other also
constrained supplies. In the longer run however, disproportionate regional pricing encourages capacity
enhancements on the interstate pipeline grid, from producing areas with excess supply, to markets with
constrained delivery capacity. Such added capacity nearly always results in a more integrated, efficient
delivery system that tends to eliminate or at least minimize such price variances.
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 have greater access to the national market
resulting in less favorable price differentials for the Pacific Northwest market. Today, wholesale prices at
the major trading points supplying the Pacific Northwest region 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.
Today, Intermountain is in an increasingly mega-regional marketplace where market conditions across
the continent - including pipeline capacities - can, and often do, affect regional supply availability and
pricing dynamics. While gas supplies are readily available and national prices show a short-term
softening trend, Intermountain is increasingly competing with markets that have historically paid higher
prices to obtain gas supplies. In the long run, many forecasts predict tightening price differentials across
the continent.
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New Pipeline Capacity
There are currently several pipeline projects proposed for the Northwest (see Figure 5 below). The first
project is by Spectra Energy to add much needed capacity South through BC. The second noted
expansion is to increase capacity from west to east in southern BC. Project numbers 3 and 4 are
designed to increase capacity into the I-5 corridor between Sumas and Portland. The last project (5) will
provide a link with existing pipeline systems that converge at Malin, OR with a proposed Coos Bay
export terminal in southern Oregon.
Figure 5 Source: NWGA 2016 Gas Outlook
None of 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
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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 the IPUC, Intermountain provides sales and transport-only services to over 320,000
customers in southern Idaho.
The clear 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 to provide an efficient mix of the above supply resources to meet its goal of providing
reliable, secure, and economic firm service to its customers. Intermountain actively manages its supply
and delivery portfolio and consistently seeks additional resources where needed. The Company actively
monitors natural gas pricing and production trends to maintain a secure, reliable and price competitive
portfolio and seeks innovative techniques to manage its transportation and storage assets to provide
both economic benefits to 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 help supplement the traditional supply-side resources during peak
demand conditions. Non-traditional resources include two general types: energy supplies not received
from an interstate pipeline supplier, producer or interstate storage operator and various methods used
to increase capacity within the Company’s distribution system that enhance the ability to flow gas
during periods of peak demand. Six (6) non-traditional supply resources and three (3) capacity upgrade
options were considered in this IRP and are as follows:
Non-Traditional Supply Resources
1. Diesel/Fuel Oil
2. Coal
3. Wood Chips
4. Propane
5. Satellite/Portable LNG Facilities
6. Biogas Production
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 coal, propane, diesel and wood chips, an industrial customer can
lower their natural gas requirement during peak load periods while continuing to receive the energy
required for their specific process. Although these alternative resources and related equipment typically
have the ability to operate any time during the year, most are ideally suited to run during peak demand
from a supply resource perspective. However, only the industrial market has the ability to use any of
the aforementioned alternate fuel in large enough volumes to make any material difference in system
demand. More specifically, only industrial customers located along the Idaho Falls Lateral (IFL) have the
ability to use any of these non-traditional resources to offset firm demand throughout a system. In
order to rely on these types of peak supplies Intermountain would need to engage in negotiations with
specific customers to ensure availability. The overall expense cost of these kinds of arrangements, if
any, is difficult to assess.
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The remaining non-traditional resource, Satellite/Portable liquid natural gas (LNG) facility, is technically
not a form of demand side management but LNG typically 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.
Diesel/Fuel Oil
There are four large volume industrial customers along the IFL that currently have the potential to use
diesel or fuel oil as a natural gas supplement. The plants are able to switch their boilers over to burn oil
and decrease a portion of their gas usage; the plants have fuel storage tanks onsite along with additional
pipelines and equipment. Burning diesel or 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.
Out of the four industrial customers that currently have equipment to burn fuel oil currently two
customers have the ability to supplement their natural gas usage, the other two customers lack the
ability due to intentionally not renewing a permit or choosing not to purchase and store fuel oil at their
facility. The estimated capital to install a diesel storage system is approximately $300,000 - $800,000
depending on usage requirements and days of storage. The estimated cost of diesel or fuel oil is
between $2.90 - $3.90 per gallon depending on fuel grade and classification, time of purchase and
quantity of purchase. The conversion cost to natural gas is roughly $2.20 to $3.00 per therm.
Coal
Coal use is very limited as a resource for firm industrial customers within Intermountain’s service
territory. A coal user must have a separate coal burning boiler installed along with their natural gas
burning boilers and typically must have additional equipment installed to transport the large quantities
of coal within their facility. Regulations and permitting requirements can also be a challenge.
Intermountain currently has a few industrial customers throughout the system that support coal backup
systems; although, only two firm industrial customers remain that have the ability and permitting to
offset gas demand with coal.
The cost of coal in the northwest is approximately $50 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 roughly at $0.27 - $0.29 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 there must be additional equipment installed, such as
wood fired boilers, wood chip transport and dry storage facilities. The wood is supplied from various
tree clearing and wood mill operations that produce chips within regulatory specifications to be used as
fuel. The chips are then transported by truck to location where the customer will typically utilize them
as a fuel source for a few months each year. The wood fired boilers are currently operated in
conjunction with natural gas boilers, and technically won’t offset gas usage. For comparison purposes,
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the wood fired boilers, if used to replace natural gas for this specific industrial customer, could offset gas
usage by approximately 7,500 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 5,000-6,000 BTU’s per
pound, which converts into 16-20 pounds of wood being burned to produce one therm of natural gas.
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. Currently there are no industrial customers on the system that
have the ability to use propane as a feasible alternative to natural gas.
Capital costs for propane facilities can become relatively high due to storage requirements. Typical
capital costs for a peak day send out of 30,000 therms per day, and the storage tanks required to sustain
this load, are approximately $600,000 - $700,000. As with oil, storage facilities should be designed to
accommodate a peak day delivery load for approximately seven (7) days. The average cost of propane
ranges from $2.10 - $2.20 per gallon, which is a natural gas equivalent to $2.29 – 2.40 per therm.
[NOTE: One gallon of propane is approximately 91,600 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 key supply 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 equipment has the ability to boil LNG back to a gaseous
form and deliver it into the distribution system by heating the liquid from -260 degree Fahrenheit to a
typical temperature of 50 – 70 degree Fahrenheit. This portable equipment is available to lease or
purchase from various companies and can be used for peak shaving at industrial plants or within a
distribution system. Regulatory and environmental approvals are minimal compared to permanent LNG
production plants and are dependent upon the specific location where the portable LNG equipment is
placed. The available delivery pressure from LNG equipment ranges from 150 psig to 650 psig with a
typical flow capability of approximately 2,000 - 8,000 therms per hour.
Intermountain Gas currently operates a portable LNG unit on the northern end of the Idaho Falls Lateral
to assist in peak shaving the system. In addition to the portable equipment, Intermountain also has a
permanent LNG facility on the IFL that is designed to accommodate the portable equipment, provide an
onsite control building and allow onsite LNG storage capabilities. The ability to store LNG onsite allows
Intermountain to partially mitigate the risk associated with relying on truck deliveries during critical flow
periods. The LNG delivery risk is also reduced now that Intermountain has the ability to withdraw LNG
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from the Nampa LNG Storage Tank and can transport this LNG around the state in a timely manner.
With Nampa LNG readily available the cost and dependence of third party supply is removed.
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.
Biogas Production
Biogas can be defined as utilizing any biomass material to produce a renewable fuel gas. Biomass is any
biodegradable organic material that can be derived from plants, animals, animal byproduct and
municipal solid waste. After processing of biogas to industry purity standards the gas can then be used
as a renewable supplement to fossil natural gas within Company facilities.
Idaho is one of the nation’s largest dairy producing states which make it a prime location for biogas
production utilizing the abundant supply of animal and farm byproducts. Southern Idaho currently has
multiple interested parties reviewing the prospect of constructing an anaerobic digester facility and
becoming a gas supplier on Intermountain’s distribution system; although, at this time, no contract for
supply has been completed. The Company continues to work closely with potential biogas producers
within the service territory.
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Capacity Upgrades
The three capacity upgrades discussed below do not reduce demand nor do they create additional
supply points, rather they increase the overall capacity of a pipeline system while utilizing the existing
gate station supply points.
Pipeline Loop
Pipeline looping is a traditional method of increasing capacity within an existing distribution system.
The loop refers to the construction of new pipe parallel to an existing pipeline that has, or may become,
a constraint point. The feasibility of looping a pipeline is primarily dependent upon the location where
the pipeline will be constructed. Installing gas pipelines through private easements, residential areas,
existing asphalt, or steep and rocky terrain can greatly increase the cost to unjustifiable amounts when
compared with alternative enhancement solutions
The potential increase in system capacity by constructing a pipeline loop is dependent on the size and
length of new pipe being installed with typical increases in capacity ranging from 50,000 – 250,000
therms per day on large, high pressure laterals. The cost for a new pipeline installation of this
magnitude is generally in the range of $7 - $20 million.
Pipeline Uprate
A quick and sometimes relatively inexpensive method of increasing capacity in an existing pipeline is to
increase the maximum allowable operating pressure of the line, usually called a pipeline uprate.
Uprates allow a company to maximize the potential of their existing systems before constructing
additional facilities and they’re normally a low cost option to increase capacity; however, leaks and
damages are sometimes found or incurred during the uprate process creating costly repairs. There are
also safety considerations and pipe regulations that restrict the feasibility of increasing the pressure in
any pipeline, such as the material composition, strength rating and relative location of the existing
pipeline.
Compressor Station
Compressor stations are a third capacity-related option. They are typically installed on pipelines or
laterals with significant gas flow and the ability to operate at higher pressures. Intermountain currently
has two such transmission pipelines for which the installation of a compressor station can be practical:
the Sun Valley Lateral and the Idaho Falls Lateral. Regulatory and environmental approvals to install a
compressor station, along with engineering and construction time, can be a significant deterrent, but
compressors can also be a cost effective, feasible solution to lateral constraint points. Compressor
stations can be broken down into the following two (2) scenarios:
A single, large volume compressor can be installed on the pipeline when there is a constant, high flow of
gas. The compressor is sized according to the natural gas flow and is placed in an optimal location along
the lateral. This type of compressor will not function properly if the flow in the pipeline has a tendency
to increase or decrease significantly. This type of station can have a price range of $3 - $6 million plus
land, and a typical O&M cost will be in the range of $100,000 - $200,000 annually.
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The second option is the installation of multiple, smaller compressors located in close proximity or
strategically placed in different locations along a lateral. Multiple compressors are very beneficial as
they allow for a large flow range, have some redundancy and use smaller and typically more reliable
drivers and compressors. These smaller compressor stations are well suited for areas where gas
demand is growing at a relatively slow and steady pace so that purchasing and installing these less
expensive compressors can be done over time. This “just in time” approach allows a pipeline to serve
growing customer demand for many years into the future while avoiding the single, rather large
expenditure to purchase a larger station. However, high land prices or the unavailability of land may
render this option economically or operationally infeasible. The cost of a smaller compressor station,
excluding land, is estimated at $1.5 - $3 million with approximate O&M costs of $50,000 - $150,000
annually.
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CAPACITY RELEASE AND MITIGATION PROCESS
Overview
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 could 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 period – a peak or winter period for
example – that would ensure delivery of additional gas supplies without having to contract more year-
round capacity which would not be used during off peak periods.
IGI Resources as Supply Manager
Pursuant to the requirements under the Services Agreement between Intermountain and IGI Resources,
Inc. (“IGI”), IGI is obligated to use its best efforts to provide Intermountain with reservation charge
mitigation on any unutilized firm transportation capacity it has throughout the year. In performing this
obligation, IGI must also insure that (1) in no way will there be any degradation of firm service to
Intermountain’s residential and commercial customers and (2) that Intermountain always has first call
rights on any of its firm transportation capacity throughout the year.
With the introduction of natural gas deregulation under FERC Order 436 in 1985 and the subsequent
FERC Orders 636, 712, 712A and 712B, the rules and regulations around capacity release transactions for
interstate pipeline capacity were developed. These rules cover such activity as (1) shipper must have
title; (2) prohibition against tying arrangements and (3) illegal buy/sell transactions. These rules and
regulations are very strict and must be adhered to always or are subject to significant fines (up to $1
million per day) if ever violated.
The interstate pipelines for which Intermountain holds capacity are Northwest and GTN. To facilitate
capacity release transactions, all pipelines have developed an Electronic Bulletin Board (“EBB”) for which
such transactions are to be posted. All released transportation capacity must be posted to the EBB and
in a manner, that allows a competing party to bid on it.
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Capacity Release Process
Over the past 10 to 15 years, IGI, because of its significant market presence in the Pacific Northwest, has
been able to generate several million dollars per year in released capacity mitigation dollars on behalf of
Intermountain for pass back to its customers and reduce the cost of unutilized firm transportation
capacity rights. In this effort, IGI can determine what the appetite is in the competitive market place for
firm transportation releases on Northwest and GTN. It does this via direct communication with third
parties or by market intelligence it receives from its marketing team as they deal with their customers
throughout the region. However, the most effective way is using the EBB. IGI performs its obligation to
Intermountain majorly in one of two ways. First, if IGI itself is interested in utilizing any of
Intermountain’s unutilized firm transportation capacity, then it determines what it believes is a market
competitive offer for such and that is then posted to the EBB as a pre-arranged deal. As a pre-arranged
deal, the transaction remains on the EBB for the requisite time and any third party is offered the
opportunity to further offer a higher bid on such component of capacity. If this is done, then IGI can
chose to match the higher bid and retain the use of the capacity or not to match and the capacity will be
awarded to the third-party bidder.
Second, if IGI is not interested in securing any unutilized capacity then it will post to the EBB as available
and subject to open bidding by any third party. As such, will be awarded to the highest bidder. It should
be noted that IGI posts to the EBB, as available capacity, certain volumes of capacity for certain periods
every month during bid week. This affords the most exposure to parties who may be interested in
securing certain capacity rights. However, to date third parties have chosen to bid on such available
capacity only a handful of times over all these years.
It should also be noted, that to protect the availability of firm transportation to Intermountain’s
residential and commercial customers during the year, all released capacity postings to the EBB,
whether pre-arranged or not, are posted as “recallable” capacity. This means that Intermountain can
“recall” the capacity if necessary to cover its customer demand.
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DISTRIBUTION SYSTEM MODELING
A natural gas pipeline is constrained by the laws of fluid mechanics which dictate that a pressure
differential must exist to move gas from a source to any other location on a system. Equal pressures
throughout a closed pipeline system indicate that neither gas flow nor demand exist within that system.
When gas is removed from some point on a pipeline system, typically during the operation of natural
gas equipment, then the pressure in the system at that point becomes lower than the supply pressure in
the system. This pressure differential causes gas to flow from the supply pressure to the point of gas
removal in an attempt to equalize the pressure throughout the distribution system. The same principle
keeps gas moving from interstate pipelines to Intermountain’s distribution systems. It is important that
engineers design a distribution system in which the beginning pressure sources, which could be from
interstate pipelines, compressor stations or regulator stations, have adequately high pressure, and the
transportation pipe specifications are designed appropriately to create a feasible and practical pressure
differential when gas consumption occurs on the system. The goal is to maintain a system design where
load demands do not exceed the system capacity; which is constrained by minimum pressure
allowances at a determined point or points along the distribution system, and maximum flow velocities
at which the gas is allowed to travel through the pipeline and related equipment.
Due to the nature of fluid mechanics there is a finite amount of natural gas that can flow through a pipe
of a certain size and length within specified operating pressures; the laws of fluid mechanics are used to
approximate this gas flow rate under these specific and ever changing conditions. This process is known
as "pipeline system modeling." Ultimately, gas flow dynamics on any given pipeline lateral and
distribution system can be ascertained for any set of known gas demand data. The maximum system
capacity is determined through the same methodology while calculating customer usage during a peak
heating degree day.
In order to evaluate intricate pipeline structures a system model is created to assist Intermountain’s
engineering team in determining the flow capacity and dynamics of those pipeline structures. For
example, before a large 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 hydraulic gas network modeling and analysis software program called Synergi
Gas, distributed and supported by DNV GL, to model all distribution systems and pipeline flow scenarios.
The software program was chosen because it is reliable, versatile, continually improving and able to
simultaneously analyze very large and diverse pipeline networks. Within the software program
individual models have been created for each of Intermountain’s various distribution systems including
high pressure laterals, intermediate pressure systems, distribution system networks and large diameter
service connections.
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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. The entire pipeline system is broken into three individual models for ease of use
and to reduce the time requirements during a model run analysis. The largest model in use consists of
approximately 66,900 nodes and 70,500 facilities which are used along with additional model inputs to
solve simultaneous equations through an iterative process, calculating pressures for over 66,600
unknown locations prior to analysis.
Synergi can analyze a pipeline system at a single point in time or the model can be specifically designed
to simulate the flow of gas over a specified period of time; which more closely simulates real life
operation utilizing gas stored in pipelines as line pack. While modeling over time an engineer can write
operations that will input and/or manipulate the gas loads, time of gas usage, valve operation and
compressor simulations within a model, and by incorporating the forecasted customer growth and
usage provided within this integrated resource plan Intermountain can determine the most likely points
where future constraints may occur. Once these high priority areas are identified, research and model
testing are conducted to determine the most practical and cost effective methods of enhancing the
constrained location. The feasibility, timeline, cost and increased capacity for each theoretical system
enhancement is determined and then placed into a comparison analysis and used within the IRP model.
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AVAILABLE AND POTENTIAL SYSTEM CAPACITY
ENHANCEMENTS
Throughout previous sections of the IRP it has been shown that projected growth throughout
Intermountain’s distribution systems could possibly create capacity deficits in the future. Through the
use of a gas modeling software program that incorporates total customer loads, existing pipe and
system configurations along with current distribution system capacities, each potential deficit has been
defined with respect to timing and magnitude. If any such deficit occurs then the evaluation of potential
system capacity enhancements are performed and provided as inputs to the optimization model.
The five identified Areas of Interest that were analyzed under design conditions are: the State Street
Lateral, Central Ada County, Canyon County, the Idaho Falls Lateral and the Sun Valley Lateral. Each of
these areas are unique in their customers served and their pipeline characteristics, and the optimization
of each requires different enhancement solutions.
State Street Lateral
The State Street Lateral is a sixteen mile stretch of high pressure, large diameter main that begins in
Caldwell and runs east along State Street serving Star, north Meridian, Eagle and into northern Boise.
The lateral is fed directly from a gate station and is back fed from another high pressure pipeline from the
south. Much of the pipeline is closely surrounded by residential and commercial structures that create a
difficult situation for construction and/or 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 that will establish a higher maximum allowable operating pressure; 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 phasing will minimize the length of pipe
that must be taken out of service along each step.
The State Street Retest enhancement is required within this IRP five year outlook. The first phase of
retesting will begin at the gate station and span a 6.6 mile section, ending near the intersection of State
Street and Highway 16. The retest enhancement will increase capacity within this Area of Interest to
allow for all growth projected in this IRP period.
Central Ada County
Central Ada County is the newest area of interest that consists of high pressure, intermediate pressure
and distribution pressure systems in an area of Ada County that contains higher than average customer
usage trends and experiences higher levels of growth and development. The system currently has high
pressure supplied from Chinden Boulevard on the north side of the defined area and high pressure
supplied from Victory Road on the south side of the defined area. The continued growth demands
between these two separate systems have begun to tax the Chinden high pressure pipeline and the
branch lines supplied from Chinden. The recent system enhancement solution completed in 2016 was to
install an 8” pipeline on Cloverdale Road that connected the Victory system, which contains surplus
capacity, to a branch of the Chinden system; which alleviated the excess demand that was supplied from
the Chinden pipeline.
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The newly installed pipeline system enhancement will setup Central Ada County for future enhancement
opportunities where the Victory pipeline could be uprated to match the Chinden pipeline; which will create
a contiguous, looped system through most of Central Ada County. Although, at this time, no additional
system enhancements are required for this area of interest within the IRP outlook.
Canyon County
The Canyon County area of interest consists of an interconnected system of high pressure pipelines that
serve communities from Star Road west to Highway 95. The system originally serving Nampa and
Caldwell was continually extended west to additional towns and industrial customers. Most recently, in
2013, the Canyon County system was connected to, and backfed from, a new pipeline being installed to
the town of Parma. This Parma Lateral 6” pipeline project provides a secondary feed to the Canyon
County area and allows for additional growth. Since 2013 the Canyon County area has experienced
additional residential and industrial customer growth, and now the 2017 IRP review shows that this
ongoing growth will require a system enhancement.
The enhancement selected for Canyon County is the replacement of an existing, high pressure pipeline
that has an unacceptable pressure loss with a larger diameter pipeline that will not constrict flow. The
enhancement project is a 12” pipeline, less than 1.5 miles long, installed on Ustick Road near Caldwell.
This enhancement will increase capacity to allow for customer growth projected for the next 5 years.
Idaho Falls Lateral
The Idaho Falls Lateral (IFL) began as a 52 mile, 10” pipeline that originated just south of Pocatello and
ended at the city of Idaho Falls. The IFL was later expanded farther to the north extending an additional
52 miles with 8” pipe to serve the growing towns of Rigby, Lewisville, Rexburg, Sugar City and Saint
Anthony. As demand has continually increased along the IFL, Intermountain Gas 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 34.5 miles of 16” pipeline loop.
In 2012 Intermountain completed the addition of Phase V, a project that extended 15.5 miles of 16” high
pressure pipeline to the north of Idaho Falls and increased the year round capacity available on the
lateral. With the addition of Phase V, and utilizing the peak shaving benefits of the Rexburg LNG Facility,
Intermountain has the capacity to serve the IFL for the next five years.
Sun Valley Lateral
The Sun Valley Lateral (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. Obtaining land in close proximity to this customer
load center is either very expensive, or simply unobtainable. In addition, long sections of the pipeline are
installed in rock that impose construction obstacles. Throughout the years Intermountain has uprated and
upgraded this existing lateral, and most recently installed a compressor station towards the south end of
the lateral, in order to maintain capacity and increase flow toward the north end of the system. These
pipeline enhancements and compression on the SVL have provided enough capacity for the lateral to
serve Intermountain’s five year forecast horizon; the SVL remains in the IRP due to continued observation
and planning for this unique 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 68 million American homes. The residential
market comprises 21% of total U.S. natural gas consumption. Over 5,400,000 commercial customers
also use natural gas for their energy needs, consuming 13% of our nation’s annual throughput. Roughly
192,000 industrial and manufacturing sector customers use natural gas in their processes, consuming
29% of the U.S. annual total. And in another fast-rising sector, 5,500 electric-power-generating units
produce 27% of total U.S. electricity, consuming 31% of annual U.S. demand. The remaining 6% is used
in oil and gas production operations as a pipeline transportation fuel and in road vehicles.
The simple reason for the widespread use of this energy source is: natural gas is the cleanest and most
efficient fossil fuel. Continued expansion of natural gas usage can help address several environmental
concerns simultaneously, including smog, acid rain, and carbon footprint.
Furthermore, 98.5% of the natural gas used in the United States comes from North America, where
supplies are abundant. The 2.5-million-mile underground natural gas delivery system has an
outstanding safety record, and is reliably capable of delivering needed energy to the end user,
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 slowly-recovering 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. Cost analysis of residential space and water heating show
that natural gas is more affordable to use than other major home energy sources. Households that use
natural gas appliance for heating, water heating, cooking and clothes drying spend an average of $840
less per year than homes using electric appliances.
Natural gas is now even more plentiful in North America, with an estimated 100 years supply at current
consumption levels. Furthermore, when new “unconventional” supplies such as coal bed methane are
included in forecasts, U.S. natural gas supplies could be extended several hundred 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. Over the recent years, new natural gas residential and commercial HVAC
equipment and appliances have become far more efficient, as Federal and State equipment efficiency
standards have taken effect. And in the existing customer group, as older, less-efficient equipment
wears out, it’s replaced with these newer, more efficient units. Thus, the entire natural gas user base
grows more efficient every year.
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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
46% less natural gas than it did in 1970, thanks largely to the aforementioned efficiency improvements.
Natural gas equipment efficiency makes economic sense in today’s new energy era, and IGC wll continue
to encourage new residential and commercial technologies as they become available.
Natural Gas Conservation Customer Education
Website
On our website, www.intgas.com, residential and small commercial customers can obtain detailed
information regarding energy conservation at home or their business. Large-volume/Industrial
customers have their own website from which they can obtain real-time gas consumption information.
Also at the website, customers can view our Energy Conservation Brochure, which was also mailed to all
330,000 core-market customers in January each year.
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In addition to bill paying and other services, IGC customers can also access their individual billing and gas
consumption history on the website. Customers can enroll online or by phone. The process is easy, and
access is immediate. IGC customer communications, mass-media advertising, website, and marketing
information all encourage customers to consider high-efficiency equipment when making their
equipment purchase or upgrade decisions.
Intermountain Gas Company’s Industrial Website was designed to allow the industrial customer access
to the most up-to-date natural gas usage information at their location. The site is accessible via the
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. Example paragraph under the sub-subtitle
header. The sub-subtitle header is the same as the subtitle header, except it has a single indentation.
Should additional titles be required inside another title, please continue this indentation trend.
Viewing Consumption
*Note: Usage information is shown in Decatherms
There are several tools to review, evaluate, and analyze the natural gas consumption at their specific
facility. The meter reads are taken hourly, and sent via radio communication to our Gas Control Center.
Once this information is in our system, it is available for viewing on the website. This is especially useful
in tracking and evaluating energy saving measures and new production procedures. History may be
downloaded as far back as January 1994 and all information is available on an hourly, weekly, monthly,
and annual basis.
IGC strives to keep this site in the most usable format for the customers, so a “feedback” button is also
included on the site to let us know how best to fulfill their needs.
Intermountain’s customer contact and marketing personnel are equipped to assist current and potential
customers with evaluating the advantages of installing high-efficiency gas equipment where possible.
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Education
IGC 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.
IGC is an active voice in Idaho’s legislative process as the lawmakers consider new, higher-efficiency
building and energy codes.
Research
The Gas Technology Institute (GTI) is our nation’s leader in ongoing natural gas R&D, as well as the
deployment and commercialization of new gas efficiency technologies. The goal for GTI is to solve
important energy challengens while creating value in the marketplace. As part of this effort, GTI
continues to perform important ongoing research and development work in the gas equipment arena
through their Utilization Technology Development (UTD) arm. The focus of this department is on
improving efficiencies of natual gas applications in residential, small commercial and industrial markets.
IGC has participated in GTI R&D projects, and will continue that collaboration as the opportunities arise.
In the Fall of 2014, GTI and IGC collaoborated on a cold-climate testing of the NextAire natural gas heat
pump. A 15-ton commercial unit was installed at the IGC Western Region building in Boise. The test
period was run for 18 months through two winter heating seasons.
At the time of installation, the NextAire was projected to have a heating efficiency of 1.2 COP; and to
save at least 30% in O&M costs while using 80% less electricity when compared to electric heat pump
equipment. Furthermore, since the NextAire does not require a separate cooling tower, a significant
reduction in water consumption, approximately 17,000 gallons, is expected.
The results of this project provided NextAire and GTI with valuable information for cold-climate
application of this technology. Overall, the system performed reliably, succesffully meeting building
heating and cooling loads across a wide range of ambient conditions, from 104° F in July 2015 to 12° F in
December 2015. Occupants reported improved comfort with the GHP VRF.
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
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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 reduced. 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. 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 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 +90% penetration rate along our service
mains, is a prime of example 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
313,000 residential customers. The average annual therm usage of an IGC space-heating-only customer
is 480 therms. That equates to a total residential therm usage of approximately 150,240,000 therms in a
year. If the total was used at the Federal efficiency minimum of 78%, then (150,240,000 X .78 =
117,187,200 therms X 100,000 btu’s/therm) or 11,718,720,000,000 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
(11,718,720,000,000 / 3,412) or 3,434,560,375 kilowatt-hours in a year to heat their homes. This is the
same as 3,434,560 megawatt hours of power saved, year in, year out.
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According to their 2013 Annual Report found on their website, Idaho Power’s total annual residential
megawatt hour sales for 2016 were 5,004,000. If the aforementioned 313,000 IGC residential customers
were using electric space heat instead of natural gas, Idaho Power’s total residential sendout would rise
to 8,438,560 mWh, a 68.6% increase, requiring considerable additional generation and transmission
facilities.
In peak terms, if these 313,000 IGC customers had electric furnaces with 25kw capacity, and just 1/3 of
them were operating simultaneously during a cold-weather winter peak, there would be an additional
winter peak load of 2,608 megawatts. Again, according to their website, Idaho Power recently
experienced a December 2016 winter peak load of 2,527 megawatts, tying the record from 2009.
Without the direct use of natural gas to heat these 313,000 homes, Idaho Power’s winter peak load
could reach 5,135 megawatts, a nearly 103% increase! This additional 2,608 megawatt peak load would
be the equivalent of more than eight 300 megawatt natural gas-fired electric generating facilities, like
Langley Gulch, all running at full capacity. 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 record
Summer peak from July 2013 of 3,407 megawatts.
In terms of recently-shed electric load, just since 1991, IGC has converted over 29,000 residential
electric heating customers to natural gas. Using the space heating consumption rates shown above,
these gas conversions save about 319,000 megawatt hours of residential sendout per year. In winter
peak terms, using the “1/3 operating simultaneously” example in the paragraph above, 241 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, IGC residential water heaters also provide significant relief to
the ever-growing hot weather electric demand. IGC has over 241,000 space and water heat customers.
If, instead these were 241,000 electric water heaters each rated at 9,000 watts, or 9kW, this would
amount to 2,169 megawatts of total load.
Ultimately, promoting and using natural gas for direct use in heating applications is the best use of the
resource, reduces electrical generation and mitigates the need for costly infrastructure expansion across
the US electric grid.
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LOST AND UNACCOUNTED FOR NATURAL GAS MONITORING
Intermountain Gas Company is pro-active in finding and eliminating sources of Lost and Unaccounted
For (LUAF) natural gas. 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 is consistently one of the best performing companies in the industry with a five-year
average LUAF percentage of .31% (See Example Below).
Based on Pipeline Hazardous Material & Safety Administration Annual Distribution Reporting
Intermountain utilizes a system to monitor and maintain a historically low amount of LUAF natural gas.
This system is made up of the following combination of business practices:
• Perform ongoing billing and meter audits
• Routinely rotate and test meters for accuracy
• Conduct leak surveys on 1-year and 4-year cycles to find leaks on the system
• Natural gas line damage prevention and monitoring
• Implementing advanced metering infrastructure system to improve meter reading audit process
• Monitor ten weather location points to ensure the accuracy of temperature related billing
factors
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• Utilize hourly temperatures for a 24-hour period, averaged into a daily temperature average,
ensuring accurate temperature averages for billing factors
Billing and Meter Audits
Intermountain conducts billing audits to identify Low Usage and Zero Usage are performed with each
billing cycle. Intermountain also works to ensure billing accuracy of newly installed meters. 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.
Table 1
Billing and Meter Audit Results
2014 2015 2016
Dead Meters 814 893 413
Drive Rate Errors 21 13 9
Pressure Errors 9 9 30
Rotate and Test Meters
Meter rotations are also an important tool in keeping LUAF levels low. Intermountain conducts regular
samples of its meters to test for accuracy. Sampled meters are pulled from the field and brought to the
meter shop for testing. The results of tests are evaluated by meter family to determine the pass/fail of a
family based on sampling procedure allowable defects. If the sample audit determined that the
accuracy of certain batches of purchased meters was in question, additional targeted samples would
take place and any necessary follow up remedial measures would be taken.
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. IGC conducts a monthly comparison to
the billed volumes as determined by the customer’s meter. If a discrepancy exists between the two
measured volumes, remedial action is taken.
Leak Survey
On a regular and programmed basis, Intermountain technicians check Intermountain’s entire
distribution system for natural gas leaks using sophisticated equipment that can detect even the
smallest leak. The surveys are done on a one-year cycle in business districts and a 4-year cycle in other
areas. This is more frequent than the code requires of 1-year and 5-year cycles. When such leaks are
identified, which is very infrequently, remedial action is immediately taken. Intermountain will repair
found leaks typically within 60 days, which is more aggressive than the industry where lower grade leaks
are often monitored for safety and not repaired immediately.
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Damage Prevention and Monitoring
Unfortunately, human error leads to unintentional excavation damage to our distribution system. When
such a gas loss situation occurs, an estimate is made of the escaped gas and that gas then becomes
“found gas” and not “lost gas”. Additionally, Intermountain is in the process of implementing a
comprehensive damage prevention program to reduce the number of gas line damages. This is being
accomplished by increasing staff to organize and implement the program and raising the amount of
public awareness initiatives.
Table 2
Line Damages with Gas Loss
2014 2015 2016
Gas loss occurrences
due to line damage 188 265 253
Advanced Metering Infrastructure
Intermountain is in the process of implementing Itron’s fixed-network metering infrastructure. This
system utilizes a fixed mounted data collector using two-way communication to endpoints and to the
repeater to collect on-demand reads and issue network commands. It provides robust collection of
time-synchronized interval data, when coupled with a meter data management system, helps
intermountain improve customer service, refine forecast consumption, manage and control tamper and
theft, synchronization of endpoint clocks, ensuring data collected territory-wide is accurately time-
stamped, and retrieval of missing interval data in the event of a network outage. The system can
facilitate a streamlined process to identify billing errors more quickly.
Weather and Temperature Monitoring
Intermountain increased the number of weather monitoring stations in the early 2000’s, from five to ten
weather location points, to ensure the accuracy of temperature related billing factors. Additionally,
Intermountain utilizes hourly temperatures for a 24-hour period, averaged into a daily temperature
average, ensuring accurate temperature averages for billing factors. The weather and temperature
monitoring provide for a better temperature component of the billing factor used to calculate customer
energy consumption.
Summary
Intermountain continues to monitor LUAF levels and continuously improves business processes to
ensure the company maintains a LUAF rate among the lowest in the natural gas distribution industry.
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 83 of 111
DEMAND SIDE MANAGMENT
Purpose
Demand Side Management (DSM) is a strategy used by utilities to optimize the end consumers’ energy
use. When paired with supply side resources, an analysis of demand side resources helps ensure
reliability and affordability of the company’s infrastructure. For most natural gas local distribution
companies (LDC’s) such as Intermountain, DSM is a modality for finding opportunities to purchase
therms through conservation as opposed to purchasing through a natural gas supplier; then delivering
the same molecules through an interstate pipeline. The methods for achieving this include encouraging
voluntary reduction to energy usage by offering conservation incentives to the LDC’s customers.
DSM Objectives
As stated in the Direct Use section, the most efficient use of natural gas is direct use for space, water
and other heat transfer applications such as cooking and clothes drying. The overall objectives of a
DSM program are:
• Provide customer service
• Accommodate high efficiency and off-peak load growth
• Mitigate the need for new staffing resources
• Maintain competitive position as low-cost energy provider
• Provide environmental benefits
• Focus soley on the most cost-effective DSM measures
Current Efficiency Incentives
Intermountain continues to offer a $200 cash rebate to customers converting their primary heat source
to natural gas and install an AFUE furnace 90% efficient or better. Total rebates issued since 2012 are
depicted in the chart below.
$43,000
$46,400
$43,600
$36,800
$31,000
$-
$5,000
$10,000
$15,000
$20,000
$25,000
$30,000
$35,000
$40,000
$45,000
$50,000
2012 2013 2014 2015 2016
Total Rebates
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 84 of 111
In addition to the rebates offered, Intermountain promotes the efficient use of natural gas through
communication with customers via bill stuffers, detailed information on www.intgas.com as well as
offering account analysis tools through its interactive account management portal. To access this portal,
consumers simply need to register using their current account number and a unique user name and
password.
Rate Schedule DSM- Residential Energy Efficiency Rebate Program
As part of the ruling on IPUC case number INT-G-16-02, Intermountain was given approval by the IPUC
to implement the tariff Rate Schedule DSM. The case is available to view at the Public Utilities
Commission website www.puc.idaho.gov . Further details than provided in this write-up regarding Rate
Schedule DSM can also be found within Exhibit 31 of the above referenced case.
Overview
The Residential Energy Efficiency Rebate Program (EE Program) was designed for the purpose of
acquiring cost-effective DSM resources in the form of natural gas therm savings and therefore lower
interstate transportiaon costs. This will be achieved through the use of rebates offered toward the
purchase and installation of qualified energy efficient natural gas equipment as well as for the
completion of new ENERGY Star™ qualified residences. The table below outlines the various “Tier’s” and
incentives available. Tier 1 applies to existing customers of Intermountain Gas upgrading existing
natural gas equipment to more efficient appliances; Tier 2 are conversion customers installing new high
efficient natural gas appliances to replace an equal appliance that uses an alternate fuel source.
ENERGY Star Certified NG Home $1,200
Existing Residential
.67+ EF NG Water
Heater $50 $75
.91 + EF NG Water
Heater $150 $200
80% AFUE NG
Fireplace Insert $200 $250
70% AFUE Fireplace
Insert $100 $200
$350 $50095% AFUE NG Furnace
H.E. 90% NG Combo
Radiant Heat $1,000 $1,200
Rebate Portfolio
New Construction
Tier 1 -(upgrade)Tier 2- (conversion)
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 85 of 111
Program Estimates
As outlined in detail in the aforementioned Case, achievable programatic estimates for therm savings in
the first program year and the following 4 years are depicted in the chart below:
When viewed in terms of cumulative affect, the acheiveable potential of this program has substantial
impact on annual therm consumption and lowers interstate transportation costs. The chart below
depicts the affect in the first 5 years alone.
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
Year 1 (2017)2018 2019 2020 2021
65,000
140,116
196,979
273,857
374,292
Th
e
r
m
s
Year
Estimated DSM Therm Savings
-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
Year 1 (2017)2018 2019 2020 2021
Th
e
r
m
s
Years
Cummulative Annual Therm Savings
Annual Therm Savings Cumulative Therm Savings
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 86 of 111
Cost Recovery Mechanism
It’s important to note the acquisition of demand-side therms through conservation merits the same
financial consideration as the acquisition of therms through supply side resources. Although the Rate
Schedule DSM tariff has been approved, an important precursor to impementaiton of this program will
be acquiring regulatory approval for a mechanism for the company to recover the costs associated with
this program. To that end, Intermountain filed an application with the IPUC on July 27th, 2017 for
approval of a mechanism that allows the company to recover the costs associated with implementing
Rate Schedule DSM. The details of this proposed mechanism can be found at the IPUC website
www.puc.idaho.gov; case INT-G-17-03. The implementation of this program, therefore, is pending the
ruling from the IPUC on this recent filing.
Summary
Technological advances in building envelopes and efficiencies of natural gas fueled appliances have
contributed to an overall reduction of individual consumption, thus saving LDC system capacity.
Reduced consumption also contributes to mitigating energy costs for the consumer, helps protect the
environment and ensures ample, lower-cost electricity for its many other valuable uses. Intermountain
will continue actively promoting the wise and efficient use of natural gas in the most cost concious
manner allowed.
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 87 of 111
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 (residential and small commercial) usage data, and industrial
(large volume commercial and transport) usage forecast 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) 2021
and includes a forecast for each of the five regional segments (Areas of Interest) of the distribution
system. Each forecast was developed under each of three different customer growth scenarios: low
case, base case, and high growth.
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 yields a daily core market load projection through
PY21 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 LDC incorporates
all the factors that will impact Intermountain’s future loads. The LDC is the basic tool used to reflect
demand in the IRP Optimization Model.
It is important to note that the Load Demand Curves represent existing resources and are intended to
identify potential capacity constraints and to assist in the long term planning process.
Customer Growth Summary Observations - Design Weather - All Scenarios
Idaho Falls Lateral
The Idaho Falls Lateral (IFL) Low Growth customer forecast projects an increase in customers of 3,797
PY17 through PY21 (Oct 1, 2016 to Sep 30, 2021) which corresponds to an annualized average growth
rate of 1.45%, Base Case customers increase by 7,923 customers (3.03% annualized growth rate), and
High Growth customers increase by 11,925 customers (4.56% annualized growth rate).
Intermountain Gas Company
2017-2021 Integrated Resource Plan
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Sun Valley Lateral
The Sun Valley Lateral (SVL) Low Growth customer forecast (PY17 – PY21) projects an increase of 454
customers (0.78% annualized growth rate), Base Case customer forecast increases by 909 customers
(1.56% annualized growth rate), and High Growth customer forecast shows an increase of 1,470
customers (2.52% annualized growth rate).
Canyon County Area
The Low Growth customer forecast (PY17 – PY21) for Canyon County Area (CCA) reflects an increase of
8,983 customers (2.65% annualized growth rate), Base Case customer forecast increases 11,562
customers (4.42% annualized growth rate), and High Growth customer forecast shows an increase of
16,527 customers (6.32% annualized growth rate).
State Street Lateral
The Low Growth customer forecast (PY17 – PY21) for the State Street Lateral (SSL) reflects an increase of
6,551 customers (2.69% annualized growth rate), Base Case customer forecast increases by 9,620
customers (3.95% annualized growth rate), and High Growth customer forecast shows an increase of
13,182 customers (5.42% annualized growth rate). SSL increased at a higher than normal rate due to
the inclusion of Emmett, ID customers as of PY19.
Central Ada Area
The Low Growth customer forecast (PY17 – PY21) for the Central Ada Area (CAA) reflects an increase of
2,729 customers (1.08% annualized growth rate), Base Case customer forecast increases by 4,853
customers (1.93% annualized growth rate), and High Growth customer forecast shows an increase of
7,337 customers (2.91% annualized growth rate).
Total Company
The Total Company (TC) Low Growth customer forecast (PY17 – PY21) projects an increase of 26,458
customers (1.54% annualized growth rate), Base Case customer forecast increases by 46,180 customers
(2.69% annualized growth rate), and High Growth customer forecast increases 71,618 customers (4.16%
annualized growth rate).
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.
Core Customer Distribution Summary - Design Weather - All Scenarios
Idaho Falls Lateral
IFL Design Weather- Annual Core Distribution (Dth)
Growth Scenario 2017 2018 2019 2020 2021
Low 6,919,764 7,027,282 7,117,376 7,255,200 7,335,233
Base 6,932,828 7,143,741 7,347,419 7,608,107 7,807,049
High 6,945,431 7,249,599 7,571,662 7,948,504 8,260,321
Intermountain Gas Company
2017-2021 Integrated Resource Plan
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IFL Normal Weather- Annual Core Distribution (Dth)
Growth Scenario 2017 2018 2019 2020 2021
Low 6,191,251 6,287,589 6,368,158 6,489,853 6,563,031
Base 6,203,063 6,391,867 6,574,006 6,805,571 6,985,212
High 6,214,466 6,486,640 6,774,707 7,110,127 7,390,837
Sun Valley Lateral
SVL Design Weather- Annual Core Distribution (Dth)
Growth Scenario 2017 2018 2019 2020 2021
Low 2,133,191 2,147,509 2,154,983 2,176,760 2,177,249
Base 2,135,000 2,164,262 2,188,194 2,227,995 2,249,140
High 2,139,059 2,199,582 2,242,841 2,301,631 2,340,576
SVL Normal Weather- Annual Core Distribution (Dth)
Growth Scenario 2017 2018 2019 2020 2021
Low 1,971,256 1,984,441 1,991,343 2,010,530 2,011,923
Base 1,973,026 2,000,075 2,022,137 2,058,010 2,078,478
High 1,976,969 2,032,878 2,072,790 2,126,147 2,163,082
Canyon County Area
CCA Design Weather- Annual Core Distribution (Dth)
Growth Scenario 2017 2018 2019 2020 2021
Low 5,935,277 6,139,473 6,359,155 6,600,038 6,788,784
Base 5,944,288 6,205,153 6,487,115 6,784,971 7,023,826
High 5,959,266 6,327,085 6,704,117 7,128,483 7,522,138
CCA Normal Weather- Annual Core Distribution (Dth)
Growth Scenario 2017 2018 2019 2020 2021
Low 4,727,812 4,890,037 5,065,295 5,257,352 5,407,473
Base 4,734,797 4,942,118 5,166,909 5,404,448 5,594,435
High 4,746,405 5,038,786 5,339,254 5,677,444 5,990,829
State Street Lateral
SSL Design Weather- Annual Core Distribution (Dth)
Growth Scenario 2017 2018 2019 2020 2021
Low 5,999,841 6,088,761 6,370,444 6,646,157 6,709,382
Base 6,009,871 6,176,212 6,536,815 6,887,290 7,029,574
High 6,020,860 6,270,281 6,722,552 7,173,934 7,406,745
Intermountain Gas Company
2017-2021 Integrated Resource Plan
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SSL Normal Weather- Annual Core Distribution (Dth)
Growth Scenario 2017 2018 2019 2020 2021
Low 4,689,725 4,759,288 4,976,045 5,194,911 5,244,424
Base 4,697,433 4,827,381 5,105,840 5,383,157 5,494,464
High 4,705,853 4,900,641 5,250,736 5,606,917 5,789,017
Central Ada Area
CAA Design Weather- Annual Core Distribution (Dth)
Growth Scenario 2017 2018 2019 2020 2021
Low 6,206,136 6,271,932 6,334,607 6,425,973 6,462,705
Base 6,213,186 6,333,087 6,450,252 6,593,206 6,684,011
High 6,220,747 6,398,131 6,579,532 6,793,204 6,947,518
CAA Normal Weather- Annual Core Distribution (Dth)
Growth Scenario 2017 2018 2019 2020 2021
Low 4,851,019 4,902,539 4,951,530 5,022,854 5,051,667
Base 4,856,427 4,950,166 5,041,770 5,153,433 5,224,481
High 4,862,235 5,000,828 5,142,607 5,309,540 5,430,278
Total Company
TC Design Weather- Annual Core Distribution (Dth)
Growth Scenario 2017 2018 2019 2020 2021
Low 44,008,520 44,689,782 45,383,028 46,292,079 46,825,015
Base 44,072,760 45,250,296 46,474,481 47,912,846 48,971,412
High 44,155,805 45,971,584 47,885,145 50,058,300 51,817,356
TC Normal Weather- Annual Core Distribution (Dth)
Growth Scenario 2017 2018 2019 2020 2021
Low 36,480,524 37,045,467 37,620,048 38,377,443 38,815,168
Base 36,533,802 37,509,518 38,524,187 39,720,512 40,593,842
High 36,602,698 38,106,632 39,692,785 41,498,381 42,952,167
Projected Capacity Deficits - Design Weather - 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 0.64% (low growth), 1.48% (base case) and
2.35% (high growth), highlighting the need for long-term planning. The next section illustrates the Areas
of Interest 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 (88,700 Dth), a peak day (January 15) delivery deficit does not occur.
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 91 of 111
IFL Design Weather Peak Day Deficit Under Existing/Planned Resources (Dth)
Growth Scenario 2017 2018 2019 2020 2021
Low 0 0 0 0 0
Base 0 0 0 0 0
High 0 0 0 0 0
Sun Valley Lateral LDC Study
When forecasted peak day send out on the Sun Valley Lateral is matched against the existing peak day
distribution capacity (19,950 Dth), a peak day delivery deficit does not occur.
SVL Design Weather Peak Day Deficit Under Existing/Planned Resources (Dth)
Growth Scenario 2017 2018 2019 2020 2021
Low 0 0 0 0 0
Base 0 0 0 0 0
High 0 0 0 0 0
Canyon County Area LDC Study
When forecasted peak day send out for the Canyon County Area is matched against the existing peak
day distribution capacity (86,000 Dth PY17-PY18 and 93,000 PY19-PY21), a peak day delivery deficit does
occur.
CCA Design Weather Peak Day Deficit Under Existing/Planned Resources (Dth)
Growth Scenario 2017 2018 2019 2020 2021
Low 0 0 0 0 0
Base 0 0 0 0 0
High 0 0 0 0 3,979
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 (67,000 Dth PY17-PY19 and 76,500 PY20-PY21), a peak day delivery deficit does not
occur.
SSL Design Weather Peak Day Deficit Under Existing/Planned Resources (Dth)
Growth Scenario 2017 2018 2019 2020 2021
Low 0 0 0 0 0
Base 0 0 0 0 0
High 0 0 0 0 0
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 92 of 111
Central Ada Area LDC Study
When forecasted peak day send out for the Central Ada Area is matched against the existing peak day
distribution capacity (71,000 Dth), a peak day delivery deficit does not occur.
CAA Design Weather Peak Day Deficit Under Existing/Planned Resources (Dth)
Growth Scenario 2017 2018 2019 2020 2021
Low 0 0 0 0 0
Base 0 0 0 0 0
High 0 0 0 0 0
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 peak day deficits based on existing and planned resources.
TC Design Weather Peak Day Surplus(Deficit) (Dth)
Growth Scenario 2017 2018 2019 2020 2021
Low 129,187 123,182 116,713 110,208 103,595
Base 129,058 118,463 107,221 96,041 84,715
High 128,890 112,382 95,001 77,020 59,247
2017 IRP vs. 2015 IRP Common Year Comparisons
This section compares the Total Company and each Area of Interest during the 3 common years of IRP
PY17 and PY15.
Total Company Design Weather/Base Growth Comparison
2017 IRP LOAD DEMAND CURVE - TC USAGE DESIGN BASE CASE (Dth)
NWP Firm Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD1 Total
2017 281,345 394,046 139,495 533,541
2018 281,345 404,501 142,135 546,636
2019 281,345 415,543 143,335 558,878
1Future growth in transport CD is limited to T-4, which does not affect Intermountain's interstate pipeline capacity
requirements.
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 93 of 111
2015 IRP LOAD DEMAND CURVE - TC USAGE DESIGN BASE CASE (Dth)
NWP Firm Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD1 Total
2017 281,345 401,828 110,217 512,045
2018 281,345 411,977 110,217 522,194
2019 281,345 422,206 110,217 532,423
1Future growth in transport CD is limited to T-4, which does not affect Intermountain's interstate pipeline capacity
requirements.
2017 IRP LOAD DEMAND CURVE - TC USAGE DESIGN BASE CASE
Over/(Under) 2015 IRP (Dth)
NWP Firm Peak Day Sendout
Transport Core Industrial
Capacity Market Firm CD1 Total
2017 0 (7,782) 29,278 21,496
2018 0 (7,476) 31,918 24,442
2019 0 (6,663) 33,118 26,455
1Future growth in transport CD is limited to T-4, which does not affect Intermountain's interstate pipeline capacity
requirements.
Total Company Peak Day Deliverability Comparison
2017 IRP PEAK DAY FIRM DELIVERY CAPABILITY (Dth)
2017 2018 2019
Maximum Daily Storage Withdrawals:
Nampa LNG 60,000 60,000 60,000
Plymouth LS 155,175 155,175 155,175
Jackson Prairie SGS 30,337 30,337 30,337
Total Storage 245,512 245,512 245,512
Maximum Deliverability (NWP) 281,345 281,345 281,345
Total Peak Day Deliverability 526,857 526,857 526,857
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 94 of 111
2015 IRP PEAK DAY FIRM DELIVERY CAPABILITY (Dth)
2017 2018 2019
Maximum Daily Storage Withdrawals:
Nampa LNG 60,000 60,000 60,000
Plymouth LS 113,200 113,200 113,200
Jackson Prairie SGS 30,337 30,337 30,337
Total Storage 203,537 203,537 203,537
Maximum Deliverability (NWP) 281,345 281,345 281,345
Total Peak Day Deliverability 484,882 484,882 484,882
2017 IRP PEAK DAY FIRM DELIVERY CAPABILITY
Over/(Under) 2015 (Dth)
2017 2018 2019
Maximum Daily Storage Withdrawals:
Nampa LNG 0 0 0
Plymouth LS 41,975 41,975 41,975
Jackson Prairie SGS 0 0 0
Total Storage 41,975 41,975 41,975
Maximum Deliverability (NWP) 0 0 0
Total Peak Day Deliverability 41,975 41,975 41,975
Total Company Peak Delivery Deficit Comparison
2017 IRP FIRM DELIVERY DEFICIT – TC DESIGN BASE CASE (Dth)
2017 2018 2019
Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0
______________________________
1Equal to the total winter sendout in excess of interstate capacity less total "peaking" storage. Peaking storage does not
require the use of Intermountain's traditional interstate capacity to deliver inventory to the citygate.
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 95 of 111
2015 IRP FIRM DELIVERY DEFICIT – TC DESIGN BASE CASE (Dth)
2017 2018 2019
Peak Day Deficit 27,163 37,312 47,541
Total Winter Deficit1 35,325 78,847 122,828
Days Requiring Additional Resources 4 4 4
______________________________
1Equal 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.
2017 IRP FIRM DELIVERY DEFICIT – TC DESIGN BASE CASE
Over/(Under) 2015 (Dth)
2017 2018 2019
Peak Day Deficit (27,163) (37,312) (47,541)
Total Winter Deficit1 (35,325) (78,847) (122,828)
Days Requiring Additional Resources (4) (4) (4)
______________________________
1Equal 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.
Idaho Falls Lateral Design Weather/Base Growth Comparison
2017 IRP LOAD DEMAND CURVE - IFL USAGE DESIGN BASE CASE (Dth)
Peak Day Sendout
Distribution Core Industrial
Transport Capacity Market Firm CD1 Total
2017 88,700 56,552 19,391 75,943
2018 88,700 58,267 19,391 77,658
2019 88,700 59,936 19,391 79,327
1Existing firm contract demand includes LV, T-5, and T-4 requirements.
Intermountain Gas Company
2017-2021 Integrated Resource Plan
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2015 IRP LOAD DEMAND CURVE - IFL USAGE DESIGN BASE CASE (Dth)
Peak Day Sendout
Distribution Core Industrial
Transport Capacity Market Firm CD1 Total
2017 95,800 72,008 23,470 95,478
2018 95,800 73,913 23,470 97,383
2019 95,800 75,828 23,470 99,298
1Existing firm contract demand includes LV, T-5, and T-4 requirements.
2017 IRP LOAD DEMAND CURVE - IFL USAGE DESIGN BASE CASE
Over/(Under) 2015 IRP (Dth)
Peak Day Sendout
Distribution Core Industrial
Transport Capacity Market Firm CD1 Total
2017 (7,100) (15,456) (4,079) (19,535)
2018 (7,100) (15,646) (4,079) (19,725)
2019 (7,100) (15,892) (4,079) (19,971)
1Existing firm contract demand includes LV, T-5, and T-4 requirements.
Idaho Falls Lateral Peak Delivery Deficit Comparison
2017 IRP FIRM DELIVERY DEFICIT – IFL DESIGN BASE CASE (Dth)
2017 2018 2019
Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0
______________________________
1Equal to the total winter sendout in excess of distribution capacity.
Intermountain Gas Company
2017-2021 Integrated Resource Plan
Page 97 of 111
2015 IRP FIRM DELIVERY DEFICIT – IFL DESIGN BASE CASE (Dth)
2017 2018 2019
Peak Day Deficit 0 1,583 3,498
Total Winter Deficit1 0 1,583 3,498
Days Requiring Additional Resources 0 1 1
______________________________
1Equal to the total winter sendout in excess of distribution capacity.
2017 IRP FIRM DELIVERY DEFICIT – IFL DESIGN BASE CASE
Over/(Under) 2015 (Dth)
2017 2018 2019
Peak Day Deficit 0 (1,583) (3,498)
Total Winter Deficit1 0 (1,583) (3,498)
Days Requiring Additional Resources 0 (1) (1)
______________________________
1Equal to the total winter sendout in excess of distribution capacity.
Sun Valley Lateral Design Weather/Base Growth Comparison
2017 IRP LOAD DEMAND CURVE -SVL USAGE DESIGN BASE CASE (Dth)
Peak Day Sendout
Distribution Core Industrial
Transport Capacity Market Firm CD1 Total
2017 19,950 15,303 1,335 16,638
2018 19,950 15,487 1,335 16,822
2019 19,950 15,656 1,335 16,991
1Existing firm contract demand includes LV, T-5, and T-4 requirements.
Intermountain Gas Company
2017-2021 Integrated Resource Plan
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2015 IRP LOAD DEMAND CURVE -SVL USAGE DESIGN BASE CASE (Dth)
Peak Day Sendout
Distribution Core Industrial
Transport Capacity Market Firm CD1 Total
2017 20,200 16,570 1,335 17,905
2018 20,200 16,788 1,335 18,123
2019 20,200 17,007 1,335 18,342
1Existing firm contract demand includes LV, T-5, and T-4 requirements.
2017 IRP LOAD DEMAND CURVE -SVL USAGE DESIGN BASE CASE
Over/(Under) 2015 (Dth)
Peak Day Sendout
Distribution Core Industrial
Transport Capacity Market Firm CD1 Total
2017 (250) (1,267) 0 (1,267)
2018 (250) (1,301) 0 (1,301)
2019 (250) (1,351) 0 (1,351)
1Existing firm contract demand includes LV, T-5, and T-4 requirements.
Sun Valley Lateral Delivery Deficit Comparison
2017 IRP FIRM DELIVERY DEFICIT – SVL DESIGN BASE CASE (Dth)
2017 2018 2019
Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0
______________________________
1Equal to the total winter sendout in excess of distribution capacity.
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2015 IRP FIRM DELIVERY DEFICIT – SVL DESIGN BASE CASE (Dth)
2017 2018 2019
Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0
______________________________
1Equal to the total winter sendout in excess of distribution capacity.
2017 IRP FIRM DELIVERY DEFICIT – SVL DESIGN BASE CASE
Over/(Under) 2015 (Dth)
2017 2018 2019
Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0
______________________________
1Equal to the total winter sendout in excess of distribution capacity.
Canyon County Area Design Weather/Base Growth Comparison
2017 IRP LOAD DEMAND CURVE-CCA USAGE DESIGN BASE CASE (Dth)
Peak Day Sendout
Distribution Core Industrial
Transport Capacity Market Firm CD1 Total
2017 86,000 55,816 26,190 82,006
2018 86,000 58,239 26,320 84,559
2019 93,000 60,921 26,320 87,241
1Existing firm contract demand includes LV, T-5, and T-4 requirements.
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2015 IRP LOAD DEMAND CURVE-CCA USAGE DESIGN BASE CASE (Dth)
Peak Day Sendout
Distribution Core Industrial
Transport Capacity Market Firm CD1 Total
2017 79,000 59,066 12,651 71,717
2018 79,000 60,121 12,651 72,772
2019 79,000 63,585 12,651 76,236
1Existing firm contract demand includes LV, T-5, and T-4 requirements.
2017 IRP LOAD DEMAND CURVE-CCA USAGE DESIGN BASE CASE
Over/(Under) 2015 (Dth)
Peak Day Sendout
Distribution Core Industrial
Transport Capacity Market Firm CD1 Total
2017 7,000 (3,250) 13,539 10,289
2018 7,000 (1,882) 13,669 11,787
2019 14,000 (2,664) 13,669 11,005
1Existing firm contract demand includes LV, T-5, and T-4 requirements.
Canyon County Area Delivery Deficit Comparison
2017 IRP FIRM DELIVERY DEFICIT – CCA DESIGN BASE CASE (Dth)
2017 2018 2019
Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0
______________________________
1Equal to the total winter sendout in excess of distribution capacity.
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2015 IRP FIRM DELIVERY DEFICIT – CCA DESIGN BASE CASE (Dth)
2017 2018 2019
Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0
______________________________
1Equal to the total winter sendout in excess of distribution capacity.
2017 IRP FIRM DELIVERY DEFICIT – CCA DESIGN BASE CASE
Over/(Under) 2015 (Dth)
2017 2018 2019
Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0
______________________________
1Equal to the total winter sendout in excess of distribution capacity.
State Street Lateral Design Weather/Base Growth Comparison
2017 IRP LOAD DEMAND CURVE -SSL USAGE DESIGN BASE CASE (Dth)
Peak Day Sendout
Distribution Core Industrial
Transport Capacity Market Firm CD1 Total
2017 67,000 57,521 1,780 59,301
2018 67,000 59,071 1,780 60,851
2019 67,000 62,308 1,780 64,088
1Existing firm contract demand includes LV, T-5, and T-4 requirements.
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2015 IRP LOAD DEMAND CURVE- SSL USAGE DESIGN BASE CASE (Dth)
Peak Day Sendout
Distribution Core Industrial
Transport Capacity Market Firm CD1 Total
2017 69,500 59,873 1,670 61,543
2018 69,500 61,345 1,670 63,015
2019 69,500 62,830 1,670 64,500
1Existing firm contract demand includes LV, T-5, and T-4 requirements.
2017 IRP LOAD DEMAND CURVE- SSL USAGE DESIGN BASE CASE
Over/(Under) 2015 (Dth)
Peak Day Sendout
Distribution Core Industrial
Transport Capacity Market Firm CD1 Total
2017 (2,500) (2,352) 110 (2,242)
2018 (2,500) (2,274) 110 (2,164)
2019 (2,500) (522) 110 (412)
1Existing firm contract demand includes LV, T-5, and T-4 requirements.
State Street Lateral Firm Delivery Deficit Comparison
2017 IRP FIRM DELIVERY DEFICIT – SSL DESIGN BASE CASE (Dth)
2017 2018 2019
Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0
______________________________
1Equal to the total winter sendout in excess of distribution capacity.
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2015 IRP FIRM DELIVERY DEFICIT – SSL DESIGN BASE CASE (Dth)
2017 2018 2019
Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0
______________________________
1Equal to the total winter sendout in excess of distribution capacity.
2017 IRP FIRM DELIVERY DEFICIT – SSL DESIGN BASE CASE
Over/(Under) 2015 (Dth)
2017 2018 2019
Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0
______________________________
1Equal to the total winter sendout in excess of distribution capacity.
Central Ada Area Design Weather/Base Growth Comparison
2017 IRP LOAD DEMAND CURVE-CAA USAGE DESIGN BASE CASE (Dth)
Peak Day Sendout
Distribution Core Industrial
Transport Capacity Market Firm CD1 Total
2017 71,000 59,506 1,490 60,996
2018 71,000 60,603 1,490 62,093
2019 71,000 61,730 1,490 63,220
1Existing firm contract demand includes LV, T-5, and T-4 requirements.
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2015 IRP LOAD DEMAND CURVE-CAA USAGE DESIGN BASE CASE (Dth)
Peak Day Sendout
Distribution Core Industrial
Transport Capacity Market Firm CD1 Total
2017 70,200 62,473 1,010 63,483
2018 70,200 64,218 1,010 65,228
2019 70,200 65,979 1,010 66,989
1Existing firm contract demand includes LV, T-5, and T-4 requirements.
2017 IRP LOAD DEMAND CURVE-CAA USAGE DESIGN BASE CASE
Over/(Under) 2015 (Dth)
Peak Day Sendout
Distribution Core Industrial
Transport Capacity Market Firm CD1 Total
2017 800 (2,967) 480 (2,487)
2018 800 (3,615) 480 (3,135)
2019 800 (4,249) 480 (3,769)
1Existing firm contract demand includes LV, T-5, and T-4 requirements.
Central Ada Area Firm Delivery Deficit Comparison
2017 IRP FIRM DELIVERY DEFICIT – CAA DESIGN BASE CASE (Dth)
2017 2018 2019
Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0
______________________________
1Equal to the total winter sendout in excess of distribution capacity.
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2017-2021 Integrated Resource Plan
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2015 IRP FIRM DELIVERY DEFICIT – CAA DESIGN BASE CASE (Dth)
2017 2018 2019
Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0
______________________________
1Equal to the total winter sendout in excess of distribution capacity.
2017 IRP FIRM DELIVERY DEFICIT – CAA DESIGN BASE CASE
Over/(Under) 2015 (Dth)
2017 2018 2019
Peak Day Deficit 0 0 0
Total Winter Deficit1 0 0 0
Days Requiring Additional Resources 0 0 0
______________________________
1Equal to the total winter sendout in excess of distribution capacity.
Intermountain Gas Company Firm Receipt Point Capacity Comparison
2017 IRP FIRM RECEIPT POINT CAPACITY - DAILY VOLUME (Dth)
Receipt Point 2017 2018 2019
Sumas 0 0 0
Stanfield 165,811 165,811 165,811
Rockies 97,478 97,478 97,478
Storage 245,512 245,512 245,512
Citygate 18,056 18,056 18,056
Total 526,857 526,857 526,857
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2015 IRP FIRM RECEIPT POINT CAPACITY - DAILY VOLUME (Dth)
Receipt Point 2017 2018 2019
Sumas 17,291 17,291 17,291
Stanfield 158,670 158,670 158,670
Rockies 84,328 84,328 84,328
Storage 143,537 143,537 143,537
Citygate 18,056 18,056 18,056
Total 421,882 421,882 421,882
2017 IRP FIRM RECEIPT POINT CAPACITY – DAILY VOLUME
Over/(Under) 2015 (Dth)
Receipt Point 2017 2018 2019
Sumas (17,291) (17,291) (17,291)
Stanfield 7,141 7,141 7,141
Rockies 13,150 13,150 13,150
Storage 101,975 101,975 101,975
Citygate 0 0 0
Total 104,975 104,975 104,975
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NON-UTILITY LNG FORECAST
Introduction
Since 1974, Intermountain has operated its Nampa LNG facility as a winter peaking supply source. The
plant is designed to liquefy natural gas into LNG and vaporize the LNG for use in the company’s
distribution system. The plant design also includes a 7 million gallon for LNG storage. The Nampa facility
served as the top of the Company’s supply stack or in other words, the last supply source that would
only be used in the event of very cold weather or extraordinary system constraints. In 2012
Intermountain begin an efficiency review that focused on how it might better utilize its Nampa asset.
Utilizing the then current IRP forecast, Intermountain determined how many gallons were projected to
be withdrawn each winter season. That analysis showed that even under Design weather assumptions,
that an excess of LNG supply and capacity would exist in each winter season.
History
Concurrent with the efficiency study, Intermountain began a study to determine the status of the
regional LNG market and contacted entities in the area who were then engaged in the non-utility LNG
business. As a direct result of those contacts, in late January 2013 Intermountain received an emergency
request to supply LNG to a small LNG-based utility located in southwestern Wyoming that had lost its
supply. This Commission immediately granted emergency authority for Intermountain to supply the
needed LNG pursuant to Case INT-G-13-01. Based on the efficiency review, the market study and the
experience gained from supplying the emergency LNG, the Company filed Case INT-G-13-02 to request
on-going authority from the IPUC to sell “excess” LNG to Non-utility customers.
Method of Forecasting
Intermountain utilized the results of the supply study in this IRP to determine how much Nampa LNG
would be needed for the Core Market during each year under the Design Weather/High Growth
scenario. To that needed amount, a “cushion” was added to account for the risk of events that could
occur outside of the company’s best planning scenario. After determining that potential need, it was
assumed the remaining capacity could be available for non-utility LNG sales. The table below shows the
results of the utility Nampa LNG withdrawal needs over the five-year period.
To this base, the Company adjusted monthly therms in the out years based information received from
the customers pursuant to the survey form sent out to each customer January 2016 (see page 44 for an
example). As shown below, the survey form included a cover letter explaining the intent and use of the
requested information with the assurance that all responses would remain confidential). The surveys
provided each customer’s historical peak day and monthly usage for the two years ending 2015.
2017
2018
2019
2020
2021
Total Projected Withdrawal 0 0 0 0 7
Maximum Day Withdrawal 0 0 0 0 7
Gross Available 580,000 580,000 580,000 580,000 579,993
Net Available (less Cushion & Rexburg) 474,700 474,700 474,700 474,700 474,693
Benefits to Customers
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Intermountain’s customers benefit from Intermountain’s LNG sales activities in several different ways.
First, Intermountain continues to defer 2.5¢ per gallon sold into a capital account and amortizes that
balance as it identifies capital costs that increased due to increased use of the Nampa facility. That
procedure directly reduces both rate base and depreciation expense. Intermountain also continues to
set aside 2.5¢ per gallon sold as an offset to increased O&M costs. Finally, Intermountain’s customers
also benefit from the 50/50 margin sharing mechanism that applies credits directly to the company’s
192 account to offset gas purchase costs.
Since April 2013, Intermountain has sold over 12 million gallons of non-utility LNG. These sales have
provided over $600,000 towards capital and O&M benefits and over $1.6 million of benefits flowed
through to customers via the Company’s PGA mechanism through a reduction in gas costs.
Additionally, the company has been selling much of its LNG to markets that use it in Idaho.
Intermountain believes that is a benefit to our state and those markets have expressed appreciation for
a local, reliable, competitively priced fuel. In fact, they have gone so far as to suggest that if the Nampa
facility was no longer able to supply LNG, it would leave a supply hole in the market that would be
difficult to fill.
On-going Challenges
LNG is a clean burning fuel that has the advantages of easy storage and transport under the right
conditions. The two biggest markets for regional LNG are trucking fleets and remote-site heat and/or
power applications. Though in relative infancy in the United States - -particularly in the Pacific
Northwest – LNG from a global perspective has a longer track record and continues to be in high
demand in energy import areas like Asia. However, since the biggest target market for Intermountain is
“big rig” diesel fuel replacement, the relatively low retail diesel prices over the past several years
has stunted the growth in the LNG trucking market and consequently offered little-to-no growth in LNG
prices resulting in flat margins per gallon sold.
A further challenge has been the lack of the largest displacement LNG engines. Because of the frequency
and magnitude of roadway inclines, the mountain west trucking industry typically rely on 15 liter
engines. However, manufacturers do not produce a 15-liter engine making it challenge to utilize natural
gas-powered engines to haul the heaviest loads. So lower diesel prices combined with the lack a 15-liter
engine LNG powered engine has hampered growth in LNG sales demand. These challenges have limited
revenue growth in Intermountain’s non-utility LNG sales.
Safeguards
For utility purposes, Intermountain maintains enough LNG in the tank to provide all withdrawal needs,
all Rexburg truck loads and all boil-off plus a cushion of 1,000,000 therms. This insulates core customers
from the risk of having no LNG should the need for needle peak withdrawals arise. Intermountain also
committed to the Commission that all volumes in the tank, regardless of intended market, would always
be available to serve the core market. Additionally, the company insulates its end-use customers from
any risk of loss due to non-utility sales.
Future
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Intermountain continues to see growing interest in LNG although market growth is still challenging. As
the market continues to look for ways to satisfy ever more stringent emissions standards, it is believed
that LNG will generate more interest. Looking to the future, the company sees flat sales margins and
slow but steady growth in LNG sales.
One advantage the company has is the ability to store large amounts of LNG in the storage tank that
would last for an extended for an extended period of time. Should the market begin to show high
growth, the company would not need more storage capacity but could merely add or upgrade its
liquefaction facility to increase the daily deliverability of LNG. Because of its storage capability, some
markets look to Nampa as a backstop supplier when other facilities might experience outages or
planned downtime.
The biggest disadvantage relates to cost of production. Stand-alone LNG production facilities do not
need storage tanks, vaporizers or other equipment designed to support peak shaving withdrawals and
can therefore operate more cheaply. In addition, newer facilities utilized more recent technology and
can simply operate more efficiently. Lower operating cost would result in the ability to offer lower sales
prices which could make it difficult for Nampa to compete on price alone.
Recommendations
Challenges to growth in sales volumes and a market facing flat margins growth remain. However,
Intermountain’s Nampa LNG facility is located in an area without direct competitors and the company
continues to try and build brand loyalty. Most oil forecasts predict that prices will strengthen while
natural gas is projected to remain flat. That differential is expected to result in an increase in diesel
prices vis a vis the cost of LNG. A longer-term increase in diesel prices should provide more opportunity
to grow non-utility LNG sales. Potential market growth, Therefore Intermountain recommends that it be
allowed to continue to operate its non-utility sales
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INFRASTRUCTURE REPLACEMENT
Intermountain Gas is committed to providing safe and reliable natural gas service to its customers. As
part of this commitment, Intermountain proactively monitors its pipeline system utilizing risk
management tools and engineering analysis. Additionally, Intermountain adheres to federal, state and
local requirements to replace or improve pipelines and infrastructure as required. Infrastructure that is
identified as a potential risk is reviewed and prioritized for replacement or risk mitigation.
As part of the IRP process, Intermountain will address two significant infrastructure replacement
projects scheduled to occur within the IRP outlook. These replacement projects are not growth driven.
Rexburg Snake River Crossing
The Rexburg Snake River crossing is an eight inch steel transmission pipeline installed under the Snake
River southwest of Rexburg, ID which has been identified as an infrastructure replacement project,
tentatively scheduled for planning year 2021. The pipeline was identified for replacement due to risk
related to the Snake River and surrounding flood plain. The location of the pipeline under the Snake
River and perpendicular to the river along its east bank leave the pipeline susceptible to loss of adequate
cover should the river’s rate of flow increase to the point of spilling over the existing bank and/or
scouring the existing river bottom.
The Rexburg Snake River crossing has been monitored and has required occasional attention. The river
bank has been rebuilt and reinforced by Intermountain to prevent undermining of the bank and reduce
the potential to flood, and Intermountain has installed engineered scour protection measures over top
of the pipeline to prevent cover loss within the river. These efforts have been successful to date;
although, due to the ongoing monitor and mitigation efforts, along with the everpresent risks associated
with this scenario, Intermountain plans to replace the existing pipeline.
Intermountain’s selected replacement method for this existing river crossing is to utilize horizontal
directional drilling, “HDD”, technology to install a new pipeline much further below the river bottom and
surrounding flood area. HDD will allow the pipeline to be installed much deeper in the ground than
conventional installation practices, and will avoid any disturbance to the Snake River and the sensitive
land surrounding the river. The significant increase in pipeline depth will mitigate the existing risk.
Aldyl-A Pipe Replacement
Intermountain has created an Integrity Management Program to proactively identify, analyze and
monitor any risk related to the pipeline system, and to create programs that will reduce or remove
those risks. In order to identify risk on the system Intermountain utilizes a risk model to manage and
assess the risk of infrastructure based on age, material, operating pressure and damage history, as well
as other considerations. The model is then used to prioritize mitigation efforts, and infrastructure
replacement projects are created as a result. Aldyl-A pipe replacement was identified as a priority from
the risk model and has become a substantial, ongoing project.
Aldyl-A is a polyethylene material created by DuPont and used in the manufacturing of pipe and fittings.
Aldyl-A pipe manufactured prior to 1984 is now known in the gas industry as being susceptible to loss of
flexibility which can allow cracking under certain circumstances. Since 2013 Intermountain has actively
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replaced Aldyl-A plastic pipe within the distribution system, and continues to replace approximately five
miles of pipeline each year; prioritized by risk metrics that are renewed annually. The Aldyl-A
replacement plan with continue through the duration of the IRP.