20170630Appendix A Sales & Load Forecast.pdf

Sffi*INTEGRATED RESOURCE PLAN
An IDACORP Company
@
APPENDIX A: SALES AND LOAD FORECAST
SAFE HARBOR STATEMENT
This document may contain forward-looking statements,
and it is important to note that the future results could
differ materially lrom those discussed. A full discussion
of the factors that could cause future results to differ
materially can be found in ldaho Power's filings with the
Securities and Exchange Commission.
@ erinted on rerycled paper
3Iffi*"INTEGRATED RESOURCE PLAN
An IDACORP CompanYti,.i ," ;,il Fii 3:
IRP
Resource planning is an ongoing process at ldaho Power. ldaho Power
prepares, files, and publishes an lntegrated Resource Plan (lRP) every two
years. ldaho Power expects that the experience gained over the next few
years will likely modify the 2O-year resource plan presented in this
document.
ldaho Power invited outside participation to help develop the 2017 lRP.
ldaho Power values the knowledgeable input, comments, and discussion
provided by the lntegrated Resource Plan Advisory Council and other
concerned citizens and customers.
It takes approximately one year for a dedicated team of individuals at
ldaho Power to prepare the lRP. The ldaho Power team is comprised of
individuals that represent many departments within the company. The IRP
team members are responsible for preparing forecasts, working with the
advisory counci! and the public, and performing all the analyses necessary
to prepare the resource plan.
ldaho Power looks fonrvard to continuing the resource planning process
with customers, public-interest groups, regulatory agencies, and other
interested parties. You can learn more about the ldaho Power resource
planning process at idahopower.com.
APPENDIX A: SALES AND LOAD FORECAST
JUNE .2017
ldaho Power Company Appendix A-Sales and Load Forecast
List of Figures ............
TeeLe oF GoNTENTS
Table of Contents............
List of Tables ..................
List of Appendices
Introduction...............
20l7IRP Sales and Load Forecast
Peak-Hour Demands
Overview of the Forecast....
I
ii
ii
5
5
lt1
.l
a.J
.J
.4
Average Load.........
Forecast Probabilities..............
Load Forecasts Based on Weather Variability
Load Forecasts Based on Economic Uncertainty ............
....5
....6
Residential........
Commercial
Irrigation
Industrial
Additional Firm Load
Micron Technology................
Simplot Fertilizer
Idaho National Laboratory
Energy Efficiency and Demand Response..
Energy Efficiency
Demand Response
Company System Peak .........
Company System Load.........
Fuel Prices
Electric Vehicles.
Net Metering ................
Other Considerations ..........
Contract Off-System Load.........
9
.t I
.15
t7
.21
))
))
))
.23
23
24
25
29
32
34
35
37
39
201 7 lntegrated Resource Plan Page i
Appendix A-Sales and Load Forecast ldaho Power Company
Table 1.
Table2.
Table 3.
Table 4.
Table 5.
Table 6.
Table 7.
Table 8.
Table 9.
Table 10.
Table ll.
Table 12.
LIST OF TABLES
Average load and peak-demand forecast scenarios ...................6
Forecast probabilities ................
System load growth (aMUD......
Residential load growth (aMW)......
Commercial load growth (aMW)......
Irrigation load growth (aMW)
Industrial load growth (aM\tr)
.......... I I
..........15
7
8
9
8
9
t7
Additional firm load growth (aMW)......
System swnmer peak load $owth (M\ID
System winterpeak load growth @SD.......
System load growth (aMW)...... ...........29
Residential fuel-price escalation (20 17 -2036) (average annual
percent change).32
LIsT oF FIGURES
Forecast system load (aMW)
Forecast residential load (aMW)................
Forecast residential use per customer (weather-adjusted kWh) ...........
Forecast commercial load (aMW)
Commercial building share----energy bills ..
..........2t
..........25
..........27
Figure l.
Figure 2.
Figure 3.
Figure 4.
Figure 5.
Figure 8.
Figure 9.
Figure 10.
Figure 11.
Figure 12.
Figure 13.
Figure 14.
Figure 15.
Figure 16.
Figure 17.
....10
.... I I
Forecast irrigation load (aMW).... I 5
.... I 8
t2
t9
Forecast industrial load (aMW) ................
Industrial electricity consumption by industry group (based on 2016 sales).
Forecast additional firm load (aMW)))
Forecast system surnmer peak (MW) ...................26
Forecast system winter peak (MW)...............27
Forecast system load (aMW) ...............30
Composition of system company electricity sales (thousands of MWh).....................31
Forecast residential electricity prices (cents per kWh).JJ
.34
Page ii
Forecast residential natural gas prices (dollars per therm)
201 7 lntegrated Resource Plan
ldaho Power Company Appendix A-Sales and Load Forecast
LIsT oF APPENDIcES
Appendix A1. Historical and Projected Sales and Load
Residential Load .........
Historical Residential Sales and Load, 197G20|6 (weather adjusted)...
Projected Residential Sales and Load, 20171036
Commercial Load.....
Historical Commercial Sales and Load, 1976-2016 (weather adjusted)
Projected Commercial Sales and Load, 2017-2036
Irrigation Load .........
Historical Irrigation Sales and Load, 1976-2016 (weather adjusted)...
Projected Irrigation Sales and Load, 2017--2036
Industrial Load ..............
Historical Industrial Sales and Load, 1976-2016 (not weather adjusted)........................
Projected Industrial Sales and Load, 2017-2036
Additional Firm Sales and Load
Historical Additional Firm Sales and Load, 1976-2016
Projected Additional Firm Sales and Load, 2017-2036
Company System Load (excluding Astaris)
Historical Company System Sales and Load, 1976-2016 (weather adjusted).
Company System Load.........
Projected Company System Sales and Load, 2017-2036
4t
4t
4t
42
43
.43
.44
.45
.45
.46
.47
.47
.48
.49
.49
50
5l
5l
52
52
2017 lntegrated Resource Plan Page iii
Appendix A-Sales and Load Forecast ldaho Power Company
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lurnooucroN
Idaho Power has preparedAppendix A-Sales and Load Forecast as part of the 2017 Integrated
Resource Plan (lRP). Appendix A includes details on the energy sales and load forecast of future
demand for electricity within the company's service area. The above-mentioned forecast covers a
2}-year period from20l7 through 2036.
The expected-case monthly average load forecast is Idaho Power's estimate of the most probable
outcome for load growth during the planning. To account for inherent uncertainty and variability,
four additional load forecasts were prepared in addition to the expected-case-a low case,
a 70ft-percentile case, a 9Oft-percentile case, and a high case, all of which are described in
more detail in this report. The high and low economic growth scenarios provide a range of
possible load growths over the planning period due to variable economic, demographic,
and other non-weather-related influences. Additional cases are developed around
the 70ft-percentile and 9Os-percentile load forecast scenarios to assist Idaho Power in reviewing
the resource requirements that would result from variable loads due to variable
weather conditions for temperatures and rainfall. It is important to note that in the IRP resource
planning process, Idaho Power uses the 70ft-percentile load forecast to account for the risk
associated with weather impacts on load.
In the expected-case scenario, Idaho Power's system load is forecast to increase to
2,142 average megawatts (aMW) by 2036 from 1,810 aMW in20l7, representing an average
yearly growth rate of 0.9 percent over the 2}-year planning period (2017-2036). In the more
critical 70s-percentile load forecast used for resource planning, the system load is forecast to
reach 2,193 aMW by 2036 (0.9% average annual growth)r. Additionally, the number of
Idaho Power active retail customers is expected to increase from the December 2016 level of
533,400 customers to nearly 755,000 customers by year-end2036 (see footnote l).
For capacity planning purposes, it is forecasted that Idaho Power's system will grow to
4,641megawatts (MW) in2036 from the all-time system peak of 3,407 MW that occurred on
Tuesday, Jluly 2,2013, at 4:00 p.m. Idaho Power's system peak increases at an average growth
rate of 1.4 percent per year over the 2O-year planning period (2017-2036).
The numerous external factors influencing the forecast are primarily economic and demographic
in nature. Moody's Analytics serves as the primary provider for this data. The national, state,
metropolitan service area (MSA), and county economic and demographic projections are tailored
to Idaho Power's service area using an in-house economic database. Specific demographic
projections are also developed for the service area from national and local census data.
I Recent company disclosures forecast load growth during the 2016 to 2035 planning period at 1.0 percent for
average enerry demand and 1.4 percent for peak-hour demand.
2017 lntegrated Resource Plan Page 1
ldaho Power Companv Aooendix A-Sales and Load Forecast
Appendix A-Sales and Load Forecast ldaho Power Company
Additional data sources used to substantiate Moody's data include the Idaho Department of
Labor, Woods & Poole, Construction Monitor, and Federal Reserve economic databases.
Economic growth assumptions influence several classes of service growth rates. The number of
households in Idaho is projected to grow at an annual rate of 1.2 percent during the forecast
period. The growth in the number of households within individual counties in Idaho Power's
service area is projected to grow faster than the remainder of the state over the planning period.
The number of households in the Boise -Nampa MSA is projected to grow even faster than the
state of Idaho, at an annual rate of 1.6 percent during the forecast period. The Boise MSA (or the
Treasure Valley) is an area that encompasses Ada, Boise, Canyon, Gem, and Owyhee counties in
southwestern Idaho. In addition, the number of households, incomes, employment,
economic output, real retail electricity prices, and customer consumption patterns are used to
develop load projections.
In addition to the economic assumptions used to drive the expected-case forecast scenario,
several assumptions were incorporated into the forecasts of the residential, commercial,
industrial, and irrigation sectors. Further discussions of these assumptions are presented below
Conservation influences on the load forecast, including Idaho Power energy efficiency
demand-side management (DSM) programs, statutory programs, and non-programmatic trends in
conservation, are included in the load forecasts of each sector. Idaho Power DSM programs are
described in detail in Idaho Power's Demand-Side Management 2016 Annual Reporr, which is
incorporated into this IRP document as Appendix B.
During the 2O-year forecast horizon, major shifts in the electric utility industry (e.g., state and
federal regulations and varying electricity prices) could influence the load forecast. In addition,
the price and volatility of substitute fuels, such as natural gas, may also impact future demand for
electricity. The high degree of uncertainty associated with such changes is reflected in the
economic high and low load growth scenarios described previously. The altemative sales and
load scenarios in Appendix A-Sales and Load Forecast were prepared under the assumption that
Idaho Power's geographic service area remains unchanged during the planning period.
Data describing the historical and projected figures for the sales and load forecast are presented
in Appendix A1 of this report.
Page 2 2017 lntegrated Resource Plan
ldaho Power Company Appendix A-Sales and Load Forecast
2017 IRP Seles AND Lono FonecAsr
Average Load
The economic and demographic variables driving the 2017 forecast have the impact of
increasing current annual sales levels throughout the planning period. The delay in the expected
"robust lift-off'of the business cycle recovery process after the Great Recession in 2008 for the
national and, to a lesser extent, service-area economy halted load growth post-recession through
2011. However, tn2012, the extended recovery process was evident, and on-balance stronger
growth was exhibited in most economic drivers relative to recent history at that time. It is
expected that economic conditions retum to long-term fundamentals during the2017 forecast
period. Significant factors and considerations that influenced the outcome of the 2017 IRP load
forecast include the following:
The load forecast used for the2017 IRP reflects a continuance of the recovery in the
service-area economy following a severe recession in 2008 and 2009. As customer
growth was at a near standstill wrtil2012, acceleration of in-migration and business
investrnent resulted in renewed growth in the residential and commercial connections
along with increased industrial activity. As of 2017, customer additions have approached
sustainable growth rates experienced prior to the housing bubble (2000-2004) and are
expected to continue.
a
The electricity price forecast used to prepare the sales and load forecast in the 2017 IRP
reflects the impact of additional plant investment and associated variable costs of
integrating new resources identified in the 2015 IRP preferred portfolio Compared to the
electricity price forecast used to prepare the 2015 IRP sales and load forecast, the20l7
IRP price forecast yields lower future prices. The retail prices are most evident after the
first two years of the planning period and can impact the sales forecast positively,
a consequence of the inverse relationship between electricity prices and
electricity demand.
There continues to be significant uncertainty associated with the industrial and
special-contract sales forecasts due to the number of parties that contact Idaho Power
expressing interest in locating operations within Idaho Power's service area,
typically with an unknown magnitude of the energy and peak-demand requirements.
Nonetheless, the expected load forecast reflects only those industrial customers that have
made a sufficient and significant binding investment, indicating a commifrnent of the
highest probability of locating in the service area. Therefore, the large numbers of
prospective businesses that have indicated an interest in locating in Idaho Power's service
area but have not made sufficient commifinents are not included in the crurent sales and
load forecast.
a
a
2017 lntegrated Resource Plan Page 3
Appendix A-Sales and Load Forecast ldaho Power Company
a The2017 irrigation sales forecast is higher than the 2015 IRP forecast throughout the
entire forecast period due to the significant trend toward more water-intensive crops,
primarily alfalfa and corn, due to growth in the dairy industry. Also, farmers have put
high-lift acreage back into production. Additionally, load increases have come from the
conversion of flood/furrow irrigation to sprinkler irrigation, primarily related to farmers
trying to reduce labor costs.
Peak-Hour Demands
As average demands as discussed in the preceding section are an integral component to the load
forecast, so zre the impact of the peak-hour demands on the system. The peak-hour forecasting
regressions are expressed as a function of the sales forecast as well as the impact of peak-day
temperatures. The peak forecast results and comparisons with previous forecasts differ for many
reasons that include the following:
The all-time system surlmer peak demand was 3,407 MW (recorded on Tuesday, July 2,
2013, at 4:00 p.m.). The system peak-hour load record was nearly matched on June 30,
2015, at 4:00 p.m., when the system peak reached3,402 MW. Idaho Power's winter
peak-hour load record is2,527 MW, recorded on January 6,2017, at 9:00 a.m. and
matched the previous record peak dated December 10,2009, at 8:00 a.m.
a
a
a
Conservation impacts, including DSM energy efficiency programs and codes and
standards, and other naturally occurring efficiencies are considered and integrated into
the sales forecast. Impacts of demand response programs (on peak) are accounted for in
the load and resource balance analysis within supply-side planning (i.e., are treated as a
supply-side peaking resource). The amount of committed and implemented DSM
programs for each month of the planning period is shown in the load and resource
balance in Appendix C-Technical Appendix.
The peak model develops peak-scenario impacts based on historical probabilities of
peak-day temperatures at the 50th, 90th, and 95tr percentiles of occurrence for each month
of the year. The 95tr percentile forecast of peak-hour demand is utilized for peak capacity
planning purposes. These normal average peak-day temperature drivers are calculated
over the 1986 to 2015 time period (the most recent 30 years).
The 2017 IRP peak-demand forecast considers the impact of the current actualized
committed and implemented energy efficiency DSM programs on peak demand.
o
Page 4 2017 lntegrated Resource Plan
ldaho Power Company Aooendix A-Sales and Load Forecast
OvenvrEw oF THE FonecAST
The sales and load forecast is constructed by developing a separate energy forecast for each of
the major customer classes: residential, commercial, irrigation, industrial, and special contracts.
In conjunction with this energy (or sales) forecast, an hour peak-load forecast was prepared.
In addition, several probability cases were developed for the energy and peak forecasts.
Assumptions for each of the individual categories, the peak hour impacts, and probabilistic case
methodologies are described in greater detail in the following sections.
Forecast Probabi I ities
Load Forecasts Based on Weather Variability
The future demand for electricity by customers in Idaho Power's service area is represented by
three load forecasts reflecting a range of load uncertainty due to weather. The expected-case
average load forecast represents the most probable projection of system load growth during the
planning period and is based on the most recent national, state, MSA, and county economic
forecasts and the resulting derived economic forecast for Idaho Power's service area.
The expected-case average load forecast assumes median temperatures and median precipitation
(i.e., there is a 50%o chance loads will be higher or lower than the expected-case loads
due to colder-than-median or hotter-than-median temperatures or wetter-than-median or
drier-than-median precipitation). Since actual loads can vary significantly depending on
weather conditions, alternative scenarios were developed that address load variability
due to varying weather conditions.
For example, Idaho Power's maximum annual average load occurs when the highest recorded
levels of heating degree days (HDD) are assumed in winter and the highest recorded levels of
cooling and growing degree days (CDD and GDD) combined with the lowest recorded level of
precipitation are assumed in summer. Conversely, the minimum annual average load occurs
when the opposite of what is described above takes place. In the 70th-percentile residential and
commercial load forecasts, temperatures in each month were assumed to be at the 70tr percentile
of HDD in wintertime and at the 70ft percentile of CDD in summertime. In the 70th-percentile
irrigation load forecast, GDD were assumed to be at the 70th percentile and precipitation at the
30ft percentile, reflecting drier-than-median weather. The 906-percentile load forecast was
similarly constructed.
For example, the median HDD in December from 1986 to 2015 (the most recent 30 years)
was 1,029, at the Boise Weather Service office. The 70th-percentile HDD is 1,060 and would be
exceeded in 3 out of l0 years. The 9Otr-percentile HDD is 1,170 and would be exceeded in I out
of 10 years. As an example, for a single month, the l00tr-percentile HDD (the coldest December
over the 30 years) is 1,449, which occurred in December 1990. This same concep was applied in
2017 lntegrated Resource Plan Page 5
Appendix A-Sales and Load Forecast ldaho Power Company
each month throughout the year for the weather-sensitive customer classes: residential,
commercial, and irrigation.
Since Idaho Power loads are highly dependent on weather, and the development of the above
mentioned two scenarios allows the careful examination of load variability and how it may
impact future resource requirements. It is important to understand that the probabilities
associated with these forecasts apply to each month. This assumes temperatures and precipitation
would maintain at the 70ft-percentile or 9Oft-percentile level continuously, throughout the entire
year. For Idaho Power to properly plan for future resource requirements, a similar methodology
is needed for the hour of maximum demand for the year (referred to as peak demand). Table I
summarizes the load scenarios prepared for the 2017 IRP.
Table 1. Average load and peakdemand forecast scenarios
Scenario
Probability
Weather Probability of Exceeding Weather Driver
Forecasts of Average Load
90b Percentile
70th Percentile
Expected Case
Forecasts of Peak Demand
95th Percentile
90th Percentile
50th Percentile
90%
70o/o
50%
95o/o
90%
50o/o
1 in 10 years
3 in 10 years
1 in 2 years
1 in 20 years
1 in 10 years
1 in 2 years
HDD, CDD, GDD, precipitation
HDD, CDD, GDD, precipitation
HDD, CDD, GDD, precipitation
Peak-day temperatures
Peak-day temperatures
Peak-day temperatures
The analysis of resource requirements is based on the 70ft-percentile average load forecast
coupled with the 956-percentile peak-demand forecast to provide a more adverse representation
of the average load and peak demand to be considered. In other Idaho Power planning, such as
the preparation of the financial forecast or the operating plan, the expected-case (50th percentile)
average-load forecast and the 90ft-percentile peak-demand forecast are typically used.
Load Forecasts Based on Economic Uncertainty
The expected-case load forecast is based on the most recent economic forecast for Idaho Power's
service area and represents Idaho Power's most probable outcome for load growth during the
planning period.
To provide risk assessment to economic uncertainty, two additional load forecasts for
Idaho Power's service area were prepared based on the expected case forecast. The forecasts
provide a range of possible load growth rates for the2017 to 2036 planning period due to high
and low economic and demographic conditions. The average growth rates for these high and low
$owth scenarios were derived from the historical distribution of one-year growth rates over the
past 25 yeas (1992-2016).
Page 6 2017 lntegrated Resource Plan
ldaho Power Company Appendix A-Sales and Load Forecast
Of the three scenarios l) the expected forecast is the median growth path,2) the standard
deviation observed during the historical time period is used to estimate the dispersion around the
expected-case scenario, and 3) the variation in growth rates will be equivalent to the variation in
growth rates observed over the past 25 years (1992-2016).
From the above methodology, two views of probable outcomes from the forecast scenarios-
the probability of exceeding and the probability of occurrence-were developed and are reported
in Table 2.The probability of exceeding the likelihood the actual load growth will be greater
than the projected growth rate in the specified scenario. For example, over the next 20 years,
there is a l0-percent probability the actual growth rate will exceed the growth rate projected in
the high scenario; additionally, it can be inferred that for the stated periods there is an 80 percent
probability the actual growth rate will fall between the low and high scenarios.
The second probability estimate, the probability of occurrence, indicates the likelihood the actual
growth will be closer to the growth rate specified in that scenario than to the growth rate
specified in any other scenario. For example, there is a26-percent probability the actual growth
rate will be closer to the high scenario than to any other forecast scenario for the entire 2}-year
planning horizon.
Table 2. Forecast probabilities
Probability of Exceeding
Scenario I -year S-year l0-year 2o-year
Low Growth
Expected Case
High Growth.
90%
50%
1Oo/o
9Oo/o
5Oo/o
1Oo/o
90%
50o/o
10o/o
90%
5Oo/o
1Oo/o
Probability of Occurrence
Scenario 1-year S-year 10-year 2O-year
Low Growth..260/o
48o/o
260/0
26%
48%
26%
260/o
48%
26%
260/o
48o/o
260/o
Expected Case
High Growth..........
This probabilistic analysis was applied to Idaho Power's system load forecast. Its impact on the
system load forecast is the sum of the individual loads of residential, commercial, industrial,
and irrigation customers, as well as special contracts (including past sales to Astaris, Inc.)
and on-system contracts (including past sales to Raft River Coop and the City of Weiser).
Results of Idaho Power's system load projections are reported in Table 3 and shown in Figure 1.
The expected-case system load-forecast growth rate averages 0.9 percent per year over the
2D-year planning period. The low scenilio projects the system load will increase at an average
rate of 0.4 percent per yeil throughout the forecast period. The high scenario projects a load
growth of 1.3 percent per year. Idaho Power has experienced both the high- and low-growth rates
in the past. These forecasts provide a range of projected growth rates that cover approximately
80 percent of the probable outcomes as measured by Idaho Power's historical experience.
2017 lntegrated Resource Plan Page 7
Appendix A-Sales and Load Forecast ldaho Power Company
Table 3. System load growth (aMW)
Growth 2017 2021 2026 2036
Annual Growth Rate
2017-2036
Expected
Low
High
1,748
1,810
1,835
1,765
1,894
1,968
1,810
1,990
2,',!11
1,891
2,142
2,351
O.4o/o
O.9o/o
1.3o/o
2,8m
2,6m
2AW
2,2n
2,0m
1,800
8m
--, .. .........
...2.a
1,600
1,4m
1,2m -
1,0m
1S6 1S1 1996 2N1 2m6 2011 2016 2@1 2@6 281 286
Weather Adjusted (excluding Astarb)
-
Expected - - HiSh
-
Low
Figure l. Forecast system load (aMW)
Page 8 2017 lntegrated Resource Plan
ldaho Power Company Appendix A-Sales and Load Forecast
ResroeNTrAL
The expected-case residential load is forecast to increase from 594 aMW in20l7 to 747 aMW in
2}36,an average annual compound growth rate of 1.2 percent. In the 70ft-percentile scenario,
the residential load is forecast to increase from 612 aMW in2017 to 772 aMW in2036,
matching the expected-case residential growth rate. The residential load forecasts are reported
in Table 4 and shown in Figure 2.
Table 4. Residentialload growth (aMW)
Growth 2017 2021 2026 2036
Annual Growth Rate
2017-2036
90th Percentile
70th Percentile
Expected Case............
643
612
594
730
695
673
681
648
628
810
772
747
1.2o/o
1.20/o
1.2o/o
1,000
900
800
700
600
500
400
300
200
100
01981 1986 1991 1996 2@1 2006 2011 2016 2U21 2026 2031 2m6
-Vvgsther
Adjusted
-
fxpscfed Case - - 70th Percentile
-
gCIh Percentile
Figure 2. Forecast residential load (aMW)
Sales to residential customers made up 32 percent of Idaho Power's system sales in 1986 and
36 percent of system sales in 2016. The residential customer proportion of system sales is
forecast to be approximately 38 percent in2036. The number of residential customers is
projected to increase to approximately 632,000 by December 2036.
2017 lntegrated Resource Plan Page 9
Appendix A-Sales and Load Forecast ldaho Power Company
The average sales per residential customer increased to over 14,700 kilowatt-hours (kWh)
in 1980 before declining to 13,100 kWh in 2001.1n2002 and 2003, residential use per customer
dropped dramatically-nearly 500 kwh per customer from 2001-the result of two years of
significantly higher electricity prices in those years combined with a weak national and
service-area economy. The reduction in electricity prices in June 2003 and a recovery in the
service-area economy caused residential use per customer to stabilize through 2007. However,
the recession in 2008 and 2009 and conservation ef[orts further reduced residential use per
customer. This trend is expected to continue, as the average sales per residential customer are
expected to decline to approximately 10,500 kwh per year in2036. Average annual sales per
residential customer are shown in Figure 3.
20,000
18,000
15,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
1981 1985 1991 2006 2026 203L 2036
Figure 3. Forecast residential use per customer (weather-adjusted kWh)
Residential customer growth in Idaho Power's service area is a function of the number of new
service-area households as derived from Moody's Analytics' May 2016 forecast of county
housing stock and demographic data. The residential-customer forecast for 2017 to 2036 shows
an average annual growth rate of 1.8 percent.
Sales to residential retail customers is an equation that considers several factors affecting
electricity sales to the residential sector. Residential sales are a function of HDD (wintertime);
CDD (summertime); the number of service-area households; the real price of electricity; and the
real price ofnatural gas.
1996 2001
!Actual
20L1 20L6 2027
r Forecast
Page 10 2017 lntegrated Resource Plan
ldaho Power Company Appendix A-Sales and Load Forecast
CorrnnaeRcrAL
The commercial category is primarily made up of Idaho Power's small general-service and
large general-service customers. Other customers associated with this category include
unmetered general service, street-lighting service, traffic-control signal lighting service,
and dusk-to-dawn customer lighting.
Within the expected-case scenario, the commercial load is projected to increase from 466 aMW
in20l7 to 535 aMW in2036 (Table 5). The average annual compound-growth rate of the
commercial load is 0.7 percent during the forecast period. The commercial load in the
70tr-percentile scenario is projected to increase from4Tl aMW in20l7 to 543 aMW in2036.
The commercial load forecasts are illustrated in Figure 4.
Table 5. Commercial load growth (aMW)
Growth 2017 2021 2026 2035
Annual Growth Rate
2017-2036
90e Percentile
7Oth Percentile
480
471
466
498
489
482
517
507
500
556
543
535
o.80/o
o.70/o
O.7o/oExpected Case.
700
600
500
zl00
300
200
100
01981 1986 1991 1996 2001 2m6 2011 2016 2t21 2@6 2c81 2036
-\
bsther Adjusted Expected Case 70th Percentile
-
90th Percentile
Figure 4. Forecast commercial load (aMW)
With a customer base of nearly 69,000, the commercial class represents the diversity of the
service area economy, ranging from residential subdivision pressurized irrigation to
2017 lntegrated Resource Plan Page 1 1
Appendix A-Sales and Load Forecast ldaho Power Company
manufacturing. Due to this diversity, the category is flrther segmented into categories associated
with common elements of energy-use influences, such as economic variables (e.g., employment),
industry (e.g., manufacturing), and building structure characteristics (e.g., offices). Figure 5
shows the breakdown of the categories and their relative sizes based on20l6 billed energy sales.
culture,15.9%
Communication,
4.Oo/o
Gonshrdion,3.0%
Olher, 1.2o/o
Healthcare,5.l%
Lodging,3.1%
, 1.60/o
trtlfgflnd,5.1%
Figure 5. Gommercial building share+nergy bilts
As indicated in Figure 5, the retail goods and service providers of the Mercantile category
represent the largest commercial category of energy use, with 25.1% percent of total 2016 use.
Total usage in this category has moderated, even considering the growth in total number of
customers. This moderation is primarily due to customer consolidation, growth in internet-based
sales, and energy efficient retrofit and new-construction technology implementation
(particularly in the area of lighting) has grown. Categories showing significant post-recession
(201 1 to 20 1 6) energy gowth include IndustriallN4anufacturin g (+19.0%), Health Care
(+19.2%), and Wholesale Trade (+17.6%).
The number of commercial customers is expected to increase at an average annual rate of
1.8 percent, reaching 97,500 customers by December2036. The commercial customer forecast
for 2017 to 2036 shows an average annual growth rate of 1.8 percent.
Page 12 201 7 lntegrated Resource Plan
ldaho Power Company Appendix A-Sales and Load Forecast
In 1986, customers in the commercial category consumed approximately l8 percent
of Idaho Power system sales, growing to 28 percent by 2016. This share is forecast to
remain at the upper end of this range throughout the planning period.
Figure 6 shows historical and forecast average use per customer (UPC) for the entire category.
The commercial-use-per-customer metric in Figure 6 represents an aggegated metric for a
highly diverse group of customers with significant difflerences in total energy use per customer,
but it is instructive in aggregate for comparative purposes.
The UPC peaked in 2001 at67,400 kWh and has declined at approximately 1.00 percent
compounded annually to 2016. The UPC is forecast to decrease at an annual rate of 1.0 percent
over the planning period. For this category, common elements that drive use down include
increases in electricity prices, business-cycle recessions, and the adoption of energy efficiency
technology. Within the commercial class UPC varies widely, reflecting the diversity of customer
mix and range of operational size.
100,000
90,000
80,0m
70,0m
60,000
50,0m
40,0m
30,000
20,0m
10,0m
0
1981 1985 1991 1995 2001 2006, 20LL 20L6 202L 2026 203L 2036
lActual r Forecast
Figure 6. Forecast commercial use per customer (weather-adjusted kWh)
Figure 7 shows the diversity in the commercial segment's UPC as well as the trend for these
sectors. The figure shows the 2016 UPC for each segment relative to the 201I UPC. A value
greater than 1.0 indicates the UPC has risen over the period. The figure supports the general
decline of the aggregated trend of Figure 6 but highlights differences in energy and economic
dynamics within the heterogeneous commercial category not evident in the residential category
201 7 lntegrated Resource Plan Page 13
Appendix A-Sales and Load Forecast ldaho Power Company
1
0.8
t.2
0.6
0.4
0.2
0
.-."c oo"' "s" .,po*
".*"..p.d."."" ..C"""
Figure 7. Commercial categories UPC, 20{6 relative to 2011
Energy efficiency implementation is a large determinant in UPC decline over time. In the
commercial sector, the primary DSM technology impact has come from lighting. The categories
of Mercantile and Office are particularly dominant in this implementation as indicated by the
UPC trend. Faster growing categories, such as Wholesale and Healthcare tend to show positive
UPC trends. Other influences on UPC include differences in price sensitivity, sensitivity to
business cycles and weather, and degree and trends in automation. In addition, category UPC can
vary when a customer's total use increases to the point where it must, by tariffrules, migrate to
an industrial (Rate 19) category. Due to tariff migration, which occurs at the boundary of
Schedule 9P (large primary commercial) and Schedule 19 (large industrial), the forecast models
aggregate the energy use of these two schedules to ensure continuity in the dependent variable.
The commercial-sales forecast equations consider several varying factors, as informed by the
regression models, and vary depending on the sub-category. Typical variables include weather:
HDD (wintertime); CDD (summertime); specific industry growth characteristics and outlook;
service-area demographics and their derivatives, such as households, employment, and small
business conditions; the real price of electricity; and energy efficiency adoption.
Page 14 2017 lntegrated Resource Plan
ldaho Power Company Appendix A-Sales and Load Forecast
lnRrcenoru
The irrigation category is comprised of agricultural irrigation service customers. Service under
this schedule is applicable to power and energy supplied to agricultural-use customers at one
point-of-delivery for operating water pumping or water-delivery systems to irrigate agricultural
crops or pasturage.
The expected-case irrigation load is forecast to increase slowly from22l aMW in20l7 to
246 aNlW in2036, an average annual compound growth rate of 0.6 percent. The expected-case,
7Otr-percentile, and 90ft-percentile scenarios forecast slow growth in irrigation load ftom20l7
to 2036.In the 706-percentile scenario, irrigation load is projected to be 235 aMW in20l7 and
260 aMW in2036. The individual irrigation load forecasts are summarized in Table 6 and
illustrated in Figure 8.
Table 6. lrrigation load growth (aMW)
Growth 2017 2021 2026 2036
Annual Growth Rate
2017-2036
90h Percentile
7Oh Percentile
254
235
221
259
240
226
279
260
246
266
247
233
o.50/o
O.SYo
0.6%Expected Case.............
400
350
300
250
200
150
100
50
''';r" -'.-.-.--.
---
01981 1986 1991 1996 2001 2006 2011 20'.t6 2021 2026 2031 2036
-\fl/sstherAdjuste6l -flpected
Case - -70th Percentile
-90th
Percentile
Figure 8. Forecast irrigation load (aMW)
The annual average loads in Table 6 and Figure 8 are calculated using the 8,760 hours in a
typical year. In the highly seasonal irrigation sector, over 97 percent ofthe annual energy is
2017 lntegrated Resource Plan Page 15
Appendix A-Sales and Load Forecast ldaho Power Company
billed during the six months from May through October, and nearly half of the annual energy is
billed in just two months, July and August. During the summer, hourly irrigation loads can reach
nearly 900 MW. In a normal July, irrigation pumping accounts for roughly 25 percent of the
energy consumed during the hour of the annual system peak and nearly 30 percent of the energy
consumed during July for general business sales. The2017 irrigation sales forecast is higher than
the 2015 IRP forecast throughout the forecast period due to the trend toward more
water-intensive crops, primarily alfalfa and corn, due to growth in the dairy industry. Also,
farmers have put high-lift acreage back into production. Additionally, the increased customer
count from the conversion of flood/funow irrigation to sprinkler irrigation, primarily related to
farmers trying to reduce labor costs, explains most of the increased energy consumption in
recent yearc.
The 2017 irrigation sales forecast model considers several factors affecting electricity sales to
the irrigation class, including temperature; precipitation; spring rainfall; Palmer Zlndex
(calculated by the National Ocean and Atmospheric Administration [NOAA] from a combination
of precipitation, temperature, and soil moisture data); Moody's Gross Product: Agriculture, -for
Idaho; Moody's Producer Price Index: Prices Received by Farmers, All Farm Products; and the
real price of electricity. Considerations were made for the unusually low electricity consumption
in the 2001 crop year due to a voluntary load-reduction program.
Actual irrigation electricity sales have grown from the 1970 level of 816,000 megawatt-hours
(MWh) to a peak amount of 2,097,000 MWh in2013.In1977, irrigation sales reached a
maximum proportion of 20 percent of Idaho Power system sales. In 2016, the irrigation
proportion of system sales was 14 percent due to the much higher relative growth in other
customer classes. By 2036, irrigation customers are projected to consume about 12 to 13 percent
of Idaho Power system sales.
Regarding customer growth, in 1980, Idaho Power had about 10,850 active irrigation accounts.
By 2016, the number of active irrigation accounts had increasedto 20,042 and is projected to be
nearly 26,000 at the end of the planning period in2036.
As with other sectors, average use per customer is an important consideration. Since 1988,
Idaho Power has experienced growth in the number of irrigation customers but slow growth in
total electricity sales (weather-adjusted) to this sector. The number of customers has increased
because customers are converting previously furrow-irrigated land to sprinkler-irrigated land.
The conversion rate is slow and the kWh use per customer is substantially lower than the average
existing Idaho Power irrigation customer. This is because water for sprinkler conversions is
drawn from canals and not pumped from deep groundwater wells. In future forecasts,
factors related to the conjunctive management of ground and surface water and the possible
litigation associated with the resolution will require consideration. Depending on the resolution
of these issues, irrigation sales may be impacted.
Page 16 2017 lntegrated Resource Plan
ldaho Power Comoanv Aooendix A-Sales and Load Forecast
IttousrRrAL
The industrial category is comprised of Idaho Power's large power service (Schedule 19)
customers requiring monthly metered demands between 1,000 kilowatts (kW) and 20,000 kW.
The category name "Industrial" is reflective of load requirements and not necessarily indicative
of the industrial nature of the customers' business.
In 1980, Idaho Power had about 112 industrial customers, which represented about 12 percent of
Idalro Power's system sales. By December 2016, the number of industrial customers had risen
to 118, representing approximately 17 percent of system sales. As mentioned earlier in the
commercial discussion, customer counts in this tariff class are impacted by migration from and
to the commercial class as dictated by the tariff rules. However, generally speaking,
customer count growth is primarily illustrative of the positive economic conditions in the service
area. Customers with load greater than Schedule l9 ranges are known as special contract
customers and are addressed in the Additional Firm Load section of this document.
In the expected-case forecast, industrial load grows from 281 aMW in20l7 to 320 aMW in
2036, an average annual growth rate of 0.7 percent (Table 7). To a large degree, industrial load
variability is not associated with weather conditions as is the case with residential, commercial,
and irrigation; therefore, the forecasts in the 70ft- and 906-percentile weather scenarios are
identical to the expected-case industrial load scenario. The industrial load forecast is pictured in
Figure 9.
Table 7. lndustrial load growth (aMIw)
Growth 2017 2021 2026 2036
Annual Growth Rate
2017-2036
Expected Case.281 297 305 320 o.70/o
2017 lntegrated Resource Plan Page 17
Appendix A-Sales and Load Forecast ldaho Power Company
450
400
350
300
250
200
150
100
50
01981 1986 1991 1S6 2fi1 2006 2011 2016 2V21 2@6 281 2086
-f56fu31 -
Expected Case Excluding impacts of DSM
Figure 9. Forecast industria! load (aMW)
As indicated in the figure, the load growth variability is impacted by both economic and other
non-weather factors, most particularly the impacts of DSM. The figure highlights the magnitude
of DSM on actual and forecast sales. In developing the forecast, customer-specific DSM
implementation is isolated, and the actual energy use is adjusted to remove the impacts of DSM
to optimize the causal influence of non-DSM causal variables. The history and forecast of DSM
is provided by the DSM specialists within Idaho Power. The economic and other independent
variables for the regression models are provided by third-party dataproviders and internally
derived time-series for Idaho Power's service area.
Figure l0 illustrates the 2016 share of each of the categories within the Rate 19 customers.
By far, the largest share of electricity was consumed by the food manufacturing sector (36%),
followed by dairy (18.7%) and electronics/technology (Electech) (7%). The categoization
scheme includes a range of industrial building types (assembly, lodging, mercantile, warehouse,
offrce, education, health care). These provide the basis for capturing, modeling, and forecasting
the shifting economic landscape that influences industrial category electricity sales.
-Ja
,
Page 18 2017 lntegrated Resource Plan
ldaho Power Company Appendix A-Sales and Load Forecast
Office- Large
2o/o
Warehouse
2o/o
Lodgi ng
L%
Health Care
60/o
Merca nti le
o%
Other
Lo/o General Mfg.
6%
Constructi on
7%
Educati on
5%Elec/High Tech
Mfe.
7o/o
Dairy-Related Mfg.
L9o/o
Assembly
5o/o
Water-
TreatmenV
Pumpling
3o/o
Food Mfg.
36%
Figure 10. lndustrial electricity consumptaon by industry group (based on 2016 sales)
The regression models and associated explanatory variables resulting from the categorization
establish the relationship between historical electricity sales and historical independent
economic, price, technological, demographic, and other influences in the form of estimated
coeffrcients from the industry group regression models applied to the appropriate forecasts of
independent time series of energy use. From this output, the history and forecast of DSM
is subtracted.
2017 lntegrated Resource Plan Page 19
Appendix A-Sales and Load Forecast ldaho Power Company
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Page 20 2017 lntegrated Resource Plan
ldaho Power Company Aooendix A-Sales and Load Forecast
AoornoNAL Frnrrn Loao
The additional firm load category consists of Idaho Power's largest customers. Idaho Power's
tariffrequires the company serve requests for electric service gleater than 20 MW under a
special-contract schedule negotiated between Idaho Power and each large-power customer.
The contract and tariff schedule are approved by the appropriate regulatory body. A special
contract allows customer-specific, cost-of-service analysis and unique operating characteristics
to be accounted for in the agreement.
Individual energy and peak-demand forecasts are developed with for special-contract customers,
including Micron Technology, Inc.; Simplot Fertilizer Company (Simplot Fertilizer); and the
Idaho National Laboratory (INL). These three special-contract customers comprise the forecast
category labeled additional firm load.
In the expected-case forecast, additional firm load is expected to increase from 108 aMW
in20l7 to 124 aMW in2036, an average growth rate of 0.7 percent per year over the
planning period (Table 8). The additional firm load energy and demand forecasts in the 70th-
and 90ft-percentile scenarios are identical to the expected-load growth scenario. The scenario
of projected additional firm load is illustrated in Figure I l.
Table 8. Additionalfirm load growth (aMW)
Growth 2017 2021 2026 2036
Annual Growth Rate
2017-2036
Expected Case.108 112 124 124 0.70/o
2017 lntegrated Resource Plan Page21
Appendix A-Sales and Load Forecast ldaho Power Company
n0
175
150
125
100
75
50
25
01981 1986 1991 1996 2m1 2m6 2011 2016 2U21 2U26 2081 286
-Actual
,-Expected Case
Figure 11. Forecast additional firm load (aMtw)
Micron Technology
Micron Technology represents Idaho Power's largest electric load for an individual customer
and employs approximately 5,000 workers in the Boise MSA. The company operates its
research and development fabrication facility in Boise and performs a variety of other activities,
including product design and support, quality assurance, systems integration and related
manufacturing, corporate services, and general services. Micron Technology's electricity use is a
function of the market demand for their products.
Simplot Fertilizer
The Simplot Fertilizer plant is the largest producer of phosphate fertilizer in the westem United
States (US). The future electricity usage at the plant is expected to grow slowly through 2016,
then stay flat throughout the remainder of the planning period.
ldaho National Laboratory
INL is part of the US Department of Energy's (DOE) complex of national laboratories. INL is
the nation's leading center for nuclear energy research and development. The DOE provided an
energy-consumption and peak-demand forecast through 2036 for the INL. The forecast calls for
loads to increase through 2024 and levelize throughout the forecast period.
Page22 2017 lntegrated Resource Plan
ldaho Power Company Aooendix A-Sales and Load Forecast
Eruenoy EFFrcrENcy AND DerurenD RESpoNSE
Energy efficiency and demand response impacts are treated differently in the forecasting and
planning process. Energy efficiency impacts (reductions in energy use) are explicitly integrated
into the forecast models. Demand response impacts are explicitly excluded from the forecast
models; the impacts of demand response are modeled in the load and resource balance as a
supply-side resource for reducing peak-demand periods.
Energy Efficiency
Energy efficiency (EE) influences on past and future load consist of utility programs,
statutory codes, and manufacturing standards for appliances, equipment, and building materials
that reduce energy consumption. As the influence of statutory codes and manufacturing
standards on residential and commercial customers has increased in importance relative to utility
programs, Idaho Power forecast models have been modified to ensure they capture these
influences. For residential models, the physical unit flow of energy-efficient products is captured
through shipment data to resellers and installers. The source for this data is the DOE (the data
also serves as input to the DOE National Energy Model [NEM]), and the data is refined by Itron
for utility-specific applications. This data captures energy-efficient installations regardless of the
source (e.g., programs, standards, and codes). However, Idaho Power closely monitors the
assumptions and impacts of DOE data to ensure the model correctly captures all energy
efficiency impacts.
Energy Efficiency data for inigation customers and some commercial and industrial customers is
not directly surveyed and collected by the DOE; therefore, models for efficiency impacts have
been developed derived from methodologies established in Itron's white paper, Incorporating
DSM into the Load Forecost.2 These approaches include; isolating historical efficiency data and
removing the impacts from historical sales (as previously discussed in application to the
industrial customers); applying historical and forecast EE as an independent variable in the
regression model (this method was utilized for the commercial customers); and marginal
comparison of DSM growth rates for historical versus forecast trend. If there is a significant
change in future trends (i.e., trends unseen by the regression model of historical energy and
conservation trends), the forecast output is adjusted to realize the trend change embedded in the
regression output. These altemate models utilize energy efficiency data provided by Idaho
Power's internal DSM group.The DSM group develops an independent energy efficiency/DSM
forecast in collaboration with AEG consultants. This data served as direct input into the
commercial, industrial, and irrigation models. The forecast developed by Idaho Power coincides
2 Stourt McMenamin and Mark Quan. Incorporating DSM into the Load Forecasl. Itron,
https://www.itron.com/nalPublishedContent/Incorporatin{/o2DDSMo/A0into%20theYo20Loado/A0Forecast.pdf
(accessed February 3, 201 l).
2017 lntegrated Resource Plan Page23
Appendix A-Sales and Load Forecast Idaho Power Company
with models that AEG developed. Output for all category forecasts are compared to the AEG
output as well as data from DOE Form 861 of utility-reported data. Data from regional utility
acquisition is compared to Idaho Power data to ensure the regional assumptions are consistent
with Idaho Power assumptions in capturing all energy savings.
Energy savings from utility energy efficiency programs are typically measured and reported at
the point of delivery (customer's meter). Therefore, energy efficiency savings are increased by
the amount of energy lost in transmitting the electricity from the generation source to the
customer's meter.
Demand Response
Beginning with the 2009 IRP, the reduction in load associated with demand response programs
has been effectively treated as a supply-side resource and accounted for in the load and resource
balance. Demand response progftrm dat4 including operational targets for demand reduction,
program expenses, and cost-eflective summaries are detailed inAppendix C-
Technical Appendix.
As supply-side resources, demand response program impacts are not incorporated into the sales
and load forecast. In the load and resource balance, the forecast of existing demand response
programs is subtracted from the peak-hour load forecast prior to accounting for existing
supply-side resources. Likewise, the performance of new demand response programs is
accounted for prior to determining the need for additional supply-side resources.
However, because energy effrciency programs have an impact on peak demand
reduction, a component of peak-hour load reduction is integrated into the sales and load
forecast models. This provides a consistent treatment of both types of progrzrms, as energy
effrciency programs are considered in the sales and load forecast, while all demand response
progftrms are included in the load and resource balance.
A thorough description of each of the energy efficiency and demand response programs is
included inAppendix B-Demand Side Management 2016 Annual Report.
Page24 2017 lntegrated Resource Plan
ldaho Power Company Appendix A-Sales and Load Forecast
COmpaNY SYSTEM Peax
System peak load includes the sum of the coincident peak demands of residential, commercial,
industrial, and irrigation customers, as well as special contracts (including Astaris, historically)
and on-system contracts (Raft River and the City of Weiser, historically).
The all-time system summer peak demand was 3,407 MW, recorded on Tuesday, Jlly 2,
2013, at 4:00 p.m. That record was approached when the peak demand reached 3,402 MW on
Tuesday, June 30, 2015, at 4:00 p.m. The system sunmer peak load growth accelerated
from 1998 to 2008 as a record number of residential, commercial, and industrial customers
were added to the system and air conditioning (A/C) became standard in nearly all new
residential homes and new commercial buildings.
Idaho Power has two peak periods: l) a winter peak, resulting primarily from space-heating
demand that normally occurs in December, January, or February and2) a larger summer peak
that normally occurs in late June or July, which coincides with cooling load and irrigation
pumping demand.
For resource planning purposes in the 95m-percentile forecast, the system srmlmer peak load is
expected to increase from 3,586 MW in 2017 to 4,641MW in 2036.In the 9Oft-percentile
forecast, the system surlmer peak load is expected to increase from 3,566 MW in 2017 to
4,613 MW in 2036, an average growth rate of 1.4 percent per year over the planning period
(Table 9).
Table 9. System summer peak load growth (MW)
Growth 2017 2021 2026 2036
Annual
Growth Rate
2017-2036
95th Percentile
90th Percentile
50th Percentile
3,586
3,566
3,46
3,819
3,797
3,668
4j02
4,O78
3,937
4,U1
4,613
4,449
'l .40/o
1.4o/o
1.4o/o
The three scenarios of projected system summer peak loads are illustrated in Figure 12. Much of
the variation in peak load is due to weather conditions. Although not entirely, unique economic
events as occurred in the summer of 2001, when the summer peak was dampened by the nearly
30-percent curtailment in irrigation load due to the 2001 voluntary load-reduction program.
2017 lntegrated Resource Plan Page 25
AppendixA-Sales and Load Forecast ldaho Power Company
5000
4,600
4,200
3,800
3,400
3,m0
2,600
z2oo
1,800
1,400
1,m0 1981 156 1Sl 1996 2@1 2006 201',t 2016 2921 2@6 2@1 286
xActrallessAstaris
-Actual -50th
Percentile
-90th
Percentile 95th Percentile
Figure 12. Forecast system summer peak (MW)
As of December 31, 2016, the all-time system winter peak demand was2,527 MW, reached on
Thursday, December 10,2009, at 8:00 a.m. and January 06,2017, at 9:00am. As shown in
Figure 13, the historical system winter peak load is much more variable than the summer system
peak load. This is because the variability of peak-day temperatures in winter months is more
significant than the variability of peak-day temperatures in summer months. The wider spread of
the winter peak forecast lines in Figure 13 illustrates the higher variability associated with winter
peak-day temperatures.
For resource planning puq)oses, 95ft-percentile forecast, the system winter peak load is expected
to increase from 2,611 MW un2017 to2,896 MW in 2036, an average growth rate of 0.5 percent
per year over the planning period (Table l0). In the 90tr-percentile forecas! the system winter
peak load is expected to increase from2,5l7 MW in 2017 to 2,846 MW in 2036, an average
growth rate of 0.9 percent per year over the planning period (Table 10). The three scenarios of
projected system winter peak load are illustrated in Figure 13.3
3 Iduho Power uses a median peak-day temperature driver in lieu of an average peak-day temperature driver in
the 50/50 peak-demand forecast scenario. The median peak-day temperature has a 50-percent probability of
being exceeded. Peakday temperatures are not normally distributed and can be skewed by one or more extreme
observations; therefore, the median temperature better reflects expected temperatures within the context of
probabilistic percentiles. The weighted average peak-day temperature drivers are calculated over the 1986 to
2015 time period (the most recent 30 years).
Page 26 2017 lntegrated Resource Plan
ldaho Power Company Appendix A-Sales and Load Forecast
Table 10. System winter peak load growth (MW)
Growth 2017 2021 2026 2036
AnnualGrowth Rate
2017-2036
95th Percentile
90th Percentile
50h Percentile
2,611
2,517
2,294
2,691
2,596
2,415
2,769
2,675
2,5U
2,896
2,846
2,732
0.50/o
O.7o/o
o.90/o
3,400
3,100
2,800
2,500
2,no
1,900
1,600
1,300
1,m0
1981{2 198ffi7 1991-92 199&97 200'lO2 200607 2011-12 201617 2021-22 2026-27 203132 2036-37
-Actual
lessAshris
-Actrd -50th
Percentile
-90th
Percentile - - 95th Percentile
Figure {3. Forecast system winter peak (iiVU)
Additionally, note the2017IRP peak-demand forecast model explicitly excludes the impact
of demand response progrcms to establish peak impacts. The exclusion allows for planning
for demand response programs and supply-side resources in meeting peak demand.
Demand response program impacts are accounted for in the IRP load and resource balance
and are reflected as a reduction in peak demand.
2017 lntegrated Resource Plan Page27
Appendix A-Sales and Load Forecast ldaho Power Company
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Page 28 2017 lntegrated Resource Plan
ldaho Power Company Appendix A-Sales and Load Forecast
CoupnNY SYSTEM Loeo
System load is the sum of the individual loads of residential, commercial, industrial,
and irrigation customers, as well as special contracts (including past sales to Astaris)
and on-system contracts (including past sales to Raft River and the City of Weiser).
The system load excludes all long-term, firm, off-system contracts.
The expected-case system load forecast is based on the output ofthe regression and forecasting
models referenced previously and represents Idaho Power's most probable load growth during
the planning period. The expected-case forecast system load growth rate averages 0.9 percent per
year from 2017 to2036. Company system load projections are reported in Table 1l and shown in
Figure 14.
In the expected-case forecast, the company system load is expected to increase from 1,810 aMW
in}Ol7 to 2,142 aMW in2036.In the 70th-percentile forecast, the company system load is
expected to increase from 1,853 aMW in20l7 to 2,193 aMW by 2036, an average growth rate
of 0.9 percent per year over the planning period (Table 11).
Table 11. System load growth (aMW)
Growth 2017 2021 2026 2036
AnnualGrowth Rate
2017-2036
90th Percentile...
70th Percentile...
Expected Case..
1,917
1,853
1,810
2,006
1,939
1,894
2,108
2,O37
1,990
2,269
2,193
2,142
O.9o/o
o.90/o
0.9%
2017 lntegrated Resource Plan Page 29
Appendix A-Sales and Load Forecast ldaho Power Company
2,800
2,500
2,no
1,900
1,600
1.300
1,m0
700 1981 1986 1991 1996 2m',t 2006 2011 2016 2021 2U26 2B',l 286
WA less Astaris
-WeatherAdjusted -Expected
Case - - 70th Percentile
-90th
Percentile
Figure {4. Forecast system load (aMW)
The system load, excluding Astarisa, porhays the current underlying general business growth
trend within the service area. However, the system load with Astaris is instructive in regard to
the impact of a new large-load customer on system load. As noted previously, the forecast
excludes any such prospective large-load customers.
Accompanied by an outlook of moderate economic growth for Idaho Power's service area
throughout the forecast period, continued growth in Idaho Power's system load is projected.
Total load is made up of system load plus long-term, firm, off-system contracts. At this time,
there are no contracts in effect to provide long-term, firm energy off-system.
The composition of system company electricity sales by year is shown in Figure 15.
Residential sales are forecast to be nearly 26 percent higher in2036, gaining 1.4 million MWh
over 2017. Commercial sales are also expected to be 15 percent higher, or 0.6 million M.Wh,
than in 2017, followed by industrial (15 percent higher, or 0.4 million additional MWh)
and irrigation (12 percent higher n2036 than20l7).
a Th. Arta.ir elemental phosphorous plant (previously FMC) was located at the western edge of Pocatello, Idaho.
Although no longer a customer of Idaho Power, Astaris had been Idaho Power's largest individual customer and,
in some years, averaged nearly 200 aMW each month. In April 2002,the special contract between Astaris and
Idaho Power was terminated.
Page 30 201 7 lntegrated Resource Plan
ldaho Power Company Appendix A-Sales and Load Forecast
20,000
18,000
15,000
14,000
12,000
10,000
9,000
5,000
4,000
2,000
0
1985 1991 1995 2001 2006 20LL 2016 202L 2026 2031 2035
Residential I Commercial lndustrial ll lrrigation lAdditional Firm Sales lAstaris
Figure 15. Gomposition of system company electricity sales (thousands of MWh)
2017 lntegrated Resource Plan Page 31
Appendix A-Sales and Load Forecast ldaho Power Company
Fue! Prices
Fuel prices, in combination with service-area demographic and economic drivers,
impact long-term trends in electricity sales. Changes in relative fuel prices can also impact the
future demand for electricity. ClassJevel and economic-sector-level regression models were
used to identifu the relationships between real historical electricity prices and their impact on
historical electricity sales. The estimated coefficients from these models were used as drivers in
the individual sales forecast models.
Short-term and long-term nominal electricity price increases are generated intemally from
Idaho Power financial models. The US Energy Information Administration (EIA) provides the
forecasts of long-term changes in nominal natural gas prices. The nominal price estimates are
adjusted for projected inflation by applying the appropriate economic deflators to arrive atreal
fuel prices. The projected average annual growth rates of fuel prices in nominal and real terms
(adjusted for inflation) are presented in Table 12.The growth rates shown are for residential fuel
prices and can be used as a proxy for fuel-price growth rates in the commercial, industrial,
and irrigation sectors.
Table 12. Residentialfue!-price escalation (2017-2036) (average annual percent change)
Nominal Real"
Electricity-2O't 7 IRP
Electricity-2O15 IRP
1.2o/o
2.Oo/o
3.7o/o
-0.7o/o
O.Oo/o
1.7%
* Adjusted for inflation
Figure 16 illustrates the average electricity price paid by Idaho Power's residential customers
over the historical period 1980 to 2016 and over the forecast period 2017 to 2036. Both nominal
and real prices are shown. In the 2017 IRP, nominal electricity prices are expected to climb to
about l3 cents per kWh by the end of the forecast period in2036. Real electricity prices
(inflation adjusted) are expected to decline over the forecast period at an average rate of
0.7 percent annually. In the 2015 IRP, nominal electricity prices were assumed to climb to
about 15 cents per kWh by 2036, and real electricity prices (inflation adjusted) were expected to
remain flat over the forecast period at an average rate of 0.0 percent annually.
The electricity price forecast used to prepare the sales and load forecast in the 2017 IRP reflected
the additional plant investnent and variable costs of integrating the resources identified in the
2015 IRP preferred portfolio. When compared to the electricity price forecast used to prepare the
2015 IRP sales and load forecast, the 2017 IRP price forecast yielded lower future prices.
The retail prices are more evidently lower in the second 10 years of the planning period and
impact the sales forecast positively, a consequence of the inverse relationship between electricity
prices and electricity demand.
Page 32 2017 lntegrated Resource Plan
ldaho Power Company Appendix A-Sales and Load Forecast
20
18
16
L4
t2
10
8
5
4
2
0
-------...!....-..-... D.........-..... ...8...- a.-.--.. a. ..:
1981 1985 1991 1995 2001 2006 20tL 2016 202L 2026 203L 2036
Nominal
-
Real Nominal - 2015lRP
Nominal - 2017lRP - - Real - 2015 IRP Real - 2017 IRP
Figure 16. Forecast residential electricity prices (cents per kwh)
Electricity prices for Idaho Power customers increased significantly in 2001 and2002 because of
the power cost adjustment (PCA) impact on rates, a direct result of the western US energy crisis
of 2000 and 2001. Prior to 200l,Idaho Power's electricity prices were historically quite stable.
From 1990 to 2000, nominal electricity prices rose only 8 percent overall, an annual average
compound growth rate of 0.8 percent annually. More recently, over the period 2006 to 2016,
nominal electricity prices rose 72 percent overall, an annual average compound growth rate of
5.6 percent annually.
Figure l7 illustrates the average natural gas price paid by Intermountain Gas Company's
residential customers over the historical period l98l to 2015 and forecast prices from 2016 to
2036. Natural gas prices remained stable and flat throughout the 1990s before moving sharply
higher in 2001. Since spiking in 2001, natural gas prices moved downward for a couple of years
before moving sharply upward in2004 through 2006. Since 2006, natural gas prices have
declined about 30 percent, compared to 2015. Nominal natural gas prices are initially expected to
drop by 8 percent tn2016, then rise at a steady pace throughout the remainder of the forecast
period until more than doubling by 2036, growing at an average rate of 3.7 percent per year.
Real natural gas prices (adjusted for inflation) are expected to increase over the same period at an
average rate of 1.7 percent annually.
2017 lntegrated Resource Plan Page 33
Appendix A-Sales and Load Forecast ldaho Power Company
s1.80
Sr.oo
s1.40
s1.20
s1.oo
so.8o
so.50
So.ao
So.2o
So.oo
1981 1986 1991 1996 2001 2006 20Lt 2016 2021 2026 2031 2036
f- . ' NominalActual I Nominal Forecast
-
Real Actual - - Real Forecast
Figure 17. Forecast residential natural gas prices (dollars per therm)
If future natural gas price increases outpace electricity price increases, the operating costs of
space heating and water heating with electricity would become more advantageous when
compared to that of natural gas. However, in the 2017 IRP price forecast, the long-term
growth rates of electricity and natural gas prices are nearly identical.
Electric Vehicles
The load forecast includes an update of the impact of plug-in electric vehicles (PEV)
on system load to reflect the future impact of this relatively new and evolving source of energy
use. While PEV consumer adoption rates in Idaho Power's service area remain relatively low,
with continued technological advancement, limiting attributes of vehicle range and re-fueling
time continue to improve the competitiveness of these vehicles to non-electric models.
Since the first introduction of the Chevy Volt and Nissan Leaf, the number of PEVs offered in
the marketplace has proliferated to over 50 models since 2007. Early in this period, PEVs were
sold with unique model rurmes (e.g., VOLT); however, as the market grows, the plug-in
technology is increasingly offered as an option to existing models (e.g., Ford Focus).
Initially, the Idaho Power forecast for PEV impact relied on third-party forecasts from
the Electric Power Research Institute (EPRI) and Oak Ridge National Laboratory due to a
lack of service-area vehicle registration data; however, beginning with the 2011 IRP,
Page 34 2017 lnlegrated Resource Plan
ldaho Power Company Aooendix A-Sales and Load Forecast
sufficient service-areadatabecame available via vehicle registration data provided by the
Idaho Transportation Department (ITD). This data provides a basis from which to develop
service-area adoption rates and support the collection of charging behavior. The methodology
continues to integrate the fuel and technology share forecasts of the DOE's NEM.
The Idaho Power vehicle share forecast uses these models as well as a Bass consumer adoption
model as informed by registration data. Load impacts from the share model output are derived
from assumptions of battery-only and hybrid plug-in shares evident from Idaho Power
observations and informed by the DOE.
Currently, the registration data collection methodology is being revised to capture vehicles sold
with PEV technology as an option (e.g., Ford Focus). The methodology will require the unique
string of characters within the vehicle identification number (VIN) to be identified and serve as a
key value in the ITD data extraction.
The PEV forecast in the IRP did include registration data for the Toyota Prius PEV but did not
capture all models for which PEV technology is sold as an option; however, to capture the
impact of these models on future adoption, the forecast used the forecast national share
assumptions from the DOE. The net effect was to rely less on the registration data than the
2015 IRP model and more on third-party assumptions, as was the case in earlier forecasts.
Net Metering
In recent years, the number of customers signing up for net-metering service (Schedule 84)
has raised dramatically, especially for residential customers. Currently, there are approximately
900 residential and 100 commercial net-metering customers. While the recent adoption of solar
is relatively strong for our service area, the current population of net-metering customers
comprises around one-fifth of 1 percent of the population of retail customers.
The installation of generating and storage equipment at customer sites will cause the demand for
electricity delivered by Idaho Power to be reshaped throughout the year. It is important to
measure the overall and future impact on the sales forecast. Therefore, this year's long term sales
forecast was adjusted downward to reflect the impact of the increase in the number of
net-metering customers, specifically solar, connecting to our system.
Schedule 84 (net-metering) customer billing histories were compared to billing histories prior to
said customer becoming a net-metering customer. The resulting average monthly
impact-per-customer (in kwh) was then multiplied by a forecast of the Schedule 84 residential
and commercial customer count to estimate the future energy impact on the sales forecast.
The forecast of net metering customers serves as a function of historical trends and current
policy considerations.
2017 lntegrated Resource Plan Page 35
Appendix A-Sales and Load Forecast ldaho Power Company
The resulting forecast of net-metering customers multiplied by the estimated use-per-customer
sales impact per customer resulted in a monthly downward adjustment to the sales forecast for
each class. At the end of the forecast period, 2036, the annual residential sales reduction was
about 18 aMW, and the commercial reduction was less than I aMW.
Page 36 2017 Integrated Resource Plan
ldaho Power Company Appendix A-Sales and Load Forecast
Ornen CorusroERATroNS
Since the residential, commercial, irrigation, and industrial sales forecasts provide a forecast of
sales as billed, it is necessary to adjust these billed sales to the proper time frame to reflect the
required generation needed in each calendar month. To determine calendar-month sales from
billed sales, the billed sales must first be converted from billed periods to calendar months to
synchronize them with the time period in which load is generated. The calendar-month sales are
then converted to calendar-month average load by adding losses and dividing by the number of
hours in each month.
Loss factors are determined by Idaho Power's Transmission Planning deparfrnent. The annual
average energy loss coeffrcients are multiplied by the calendar-month load, yielding the
system load, including losses. A system loss study of 2012 was completed in May 2014.
The results of the study concluded that on average, the revised loss coeffrcients were lower than
those applied to generation forecasts developed prior to the 2015 IRP and were used in the
development of the 2017 IRP sales and load forecast. This resulted in a one-time permanent
reduction of nearly 20 aMW to the load forecast annually.
2017 lntegrated Resource Plan Page 37
Appendix A-Sales and Load Forecast ldaho Power Company
This page left blank intentionally.
Page 38 2017 lntegrated Resource Plan
ldaho Power Company Appendix A-Sales and Load Forecast
CournAcr Orr-SysrEM Loeo
The contract oflsystem category represents long-term contracts to supply firm energy to
off-system customers. Long-term contracts are contracts effective during the forecast period
lasting for more than one year. At this time, there are no long-term contracts.
The historical consumption for the contract off-system load category was considerable in the
early 1990s; however, after 1995, off-system loads declined through 2005. As intended,
the off-system contracts and their corresponding energy requirements expired as Idaho Power's
surplus energy diminished due to retail load growth. In the future, Idaho Power may enter
additional long-term contracts to supply firm energy to off-system customers if surplus energy
is available.
201 7 lntegrated Resource Plan Page 39
Appendix A-Sales and Load Forecast ldaho Power Company
This page left blank intentionally.
Page 40 2017 Integrated Resource Plan
ldaho Power Company Aooendix A1. Historical and Proiected Sales and Load
Appendix A1. Historical and Projected Sales and Load
ResidentialLoad
Historical Residential Sales and Load, 1976-2016 (weather adjusted)
Year
Average
Customers
Percent
Change
kWh per
Customer
Percent
Change
Average
Load (aMW)
Billed Sales
(thousands of MWh)
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
5.Oo/o
5.5%
4.3%
3.3%
1.9%
1.5o/o
1.5o/o
1.3o/o
1.',|o/o
O.8o/o
O.$Yo
O.8o/o
1.1o/o
2.Oo/o
2.1o/o
2.70/o
3.4o/o
3.7%
3.5o/o
3.3o/o
3.0%
2.9o/o
3.2o/o
3.O%
2.7o/o
2.60/o
2.8%
3.20/o
3.6Yo
3.BYo
2.50/o
1.3Yo
O.7o/o
0.6%
O.SVo
0.9%
1.3%
1.5o/o
1.7%
1.9o/o
13,280
13,240
14,559
13,904
14,657
14,583
13,54
14,287
14,078
13,988
14,095
13,960
14,237
14,237
14,223
14,428
14,099
14,124
13,991
13,950
13,713
13,640
13,681
13,548
13,365
13,128
12,641
12,673
12,675
12,668
12,884
12,922
12,838
12,688
12,421
12,361
12,251
11,968
11,873
11,558
11,515
2,3U
2,444
2,834
2,822
3,073
3,115
2,935
3,141
3,135
3,150
3,20',1
3,195
3,285
3,323
3,387
3,509
3,521
3,648
3,748
3,866
3,925
4,019
4,150
4,239
4,309
4,346
4,295
4,426
4,569
4,733
4,995
5,134
5,'t68
5,141
5,062
5,066
5,067
5,013
5,047
4,996
5,071
4.7o/o
16.0%
-0.4o/o
8.9o/o
1.4o/o
-5.8o/o
7.Oo/o
-O.2Yo
o.50/o
1.60/o
-O.2o/o
2.8%
1.1o/o
1.9%
3.60/o
o.4%
3.60/o
2.7o/o
3.2%
1.5o/o
2.4o/o
3.2o/o
2.2o/o
1.60/o
O.9o/o
-1 .2o/o
3.Oo/o
3.2%
3.604
5.5%
2.8o/o
O.7o/o
-O.5o/o
-1 .5o/o
O.1o/o
O.0o/o
-1.1o/o
O.7o/o
-1 .Oo/o
1.5o/o
267
284
320
329
350
353
337
358
357
360
365
365
375
380
388
401
402
417
429
442
448
459
474
484
492
495
491
506
522
543
571
587
589
586
578
577
576
575
573
572
579
175,720
184,561
194,650
202,982
209,629
213,579
216,696
219,U9
222,695
225,185
227,O81
228,868
230,771
233,370
238,117
243,207
249,767
258,271
267,854
277,131
286,227
294,674
303,300
312,901
322,402
331,009
339,764
349,219
360,462
373,602
387,707
397,286
402,520
405,144
407,551
409,786
413,610
418,892
425,036
432,275
4r',0,ffi2
2017 lntegrated Resource Plan Page 41
Appendix A1. Historical and Projected Sales and Load ldaho Power Company
Projected Residential Sales and Load, 2017-2036
Year
Average
Customerc
Percent
Change
kWh per
Customer
Percent
Change
Average
Load (aMW)
Billed Sales
(thousands of MWh)
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
20u
2035
2036
4r',8,%7
458,024
467,730
477,773
487,898
498,339
509,058
519,U2
529,711
539,237
il8,388
557,228
565,899
574,48
582,924
591,436
600,040
608,899
617,979
627,295
1.9o/o
2.Oo/o
2.1o/o
2.1o/o
2.1%
2.1%
2.2o/o
2.',\%
1.9o/o
1.8o/o
1.7o/o
1.60/o
1.60/o
1.5o/o
1.5o/o
1.5o/o
1.5o/o
1.5o/o
1.5o/o
1.5o/o
11,565
11,ffi
11,518
11,372
11,260
11,212
11,159
't't,092
11,000
10,921
10,882
10,843
10,792
'10,731
10,666
10,588
10,!w
10,510
10,474
10,452
5,192
5,288
5,388
5,433
5,494
5,588
5,681
5,764
5,827
5,889
5,967
6,O42
6,107
6,165
6,218
6,262
6,327
6,399
6,473
6,557
2.4%
1.8%
1.9o/o
O.8o/o
1.1o/o
1.7%
1.7%
15%
1.1o/o
1.1%
1.3%
1.3%
1.1%
0.9%
0.9o/o
O.7o/o
1.Oo/o
1.1%
1.1%
1.3o/o
594
605
615
619
628
639
649
657
666
673
682
688
698
704
710
713
723
731
740
747
Page 42 2017 lntegrated Resource Plan
ldaho Power Company Appendix A1. Historical and Proiected Sales and Load
Gommercial Load
Historical Commercial Sales and Load, 1976-2016 (weather adjusted)
Year
Average
Customers
Percent
Change
kWh per
Customer
Percent
Change
Average
Load (aMW)
Billed Sales
(thousands of MWh)
1976
1977
1978
1979
1980
1981
't982
1983
1984
1985
1986
1 987
1988
'1989
1990
1991
1992
1993
1994
1995
1996
1 997
1 998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
26,OU
27,112
27,831
28,O87
28,797
29,567
30,167
30,776
31,554
32,418
33,208
33,975
34,723
35,638
36,785
37,922
39,022
40,047
41,629
43,165
44,995
46,819
48,404
49,430
50,117
51,501
52,915
54,194
55,577
57,145
59,050
61,640
63,492
u,151
u,421
64,921
65,599
66,357
67,1',13
68,000
68,883
4.1o/o
2.7o/o
0.9%
2.5%
2.7o/o
2.0%
2.0%
2.5%
2.7o/o
2.4o/o
2.3%
2.2o/o
2.60/o
3.2o/o
3.1o/o
2.9Yo
2.60/o
4.0o/o
3.7o/o
4.2o/o
4.1o/o
3.4o/o
2.1o/o
1.4o/o
2.8o/o
2.70/o
2.4o/o
2.60/o
2.9Yo
3.3Yo
4.4o/o
3.Oo/o
1.Oo/o
o.4%
o.8%
1.Oo/o
1.2%
'l .10/o
1.3o/o
1.3o/o
52,519
52/02
52,502
56,369
54,161
54,302
54,124
52,650
53,560
54,180
53,937
53,395
14,371
55,376
55,746
56,273
56,396
58,1 83
58,274
58,695
62,013
62,056
62,718
64,170
65,965
67,426
u,794
64,zil
63,942
63,504
63,484
63,352
62,246
59,671
58,853
58,431
58,896
58,599
58,948
58,491
58,046
1,367
1,421
1,461
1,583
1,560
1,606
1,633
1,620
1,690
1,756
1,791
1,814
1,888
1,973
2,051
2,134
2,201
2,330
2,426
2,534
2,790
2,905
3,036
3,172
3,306
3,472
3,429
3,482
3,554
3,629
3,749
3,905
3,952
3,828
3,791
3,793
3,863
3,888
3,956
3,977
3,998
3.9%
2.8o/o
8.4o/o
-1 .50/o
2.9o/o
1.70/o
-0.8%
4.3o/o
3.9Yo
2.Oo/o
1.3o/o
4.10/o
4.5o/o
3.90/o
4.1o/o
3.1o/o
5.9Yo
4.1o/o
4.4o/o
10.1o/o
4.1o/o
4.5o/o
4.50/o
4.2o/o
5.Oo/o
-1 .3o/o
1.60/o
2.10/o
2.1o/o
3.3o/o
4.2o/o
1.2o/o
-3.1o/o
-1.O%
o.1%
1.8%
0.60/0
1.7%
0.5o/o
O.5o/o
157
162
169
180
178
184
186
185
193
201
204
207
216
226
235
244
251
266
278
290
319
332
348
362
378
396
392
398
405
415
429
446
449
438
432
433
440
446
452
455
456
2017 lntegrated Resource Plan Page 43
Appendix A1. Historical and Projected Sales and Load ldaho Power Company
Projected Commercial Sales and Load, 2017-2036
Year
Average
Customers
Percent
Change
kWh per
Customer
Percent
Change
Average
Load (aMW)
Billed Sales
(thousands of MWh)
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
203/.
2035
2036
69,911
7',t,070
723M
73,720
75,165
76,660
78,208
79,791
81,371
82,914
84,419
85,894
87,350
88,792
90,227
91,661
93,103
94,563
96,046
97,553
1.5o/o
1.7%
1.8o/o
'l .90/o
2.Oo/o
2.OYo
2.OYo
2.OYo
2.Oo/o
1.9%
1.8o/o
'l .70/o
1.7o/o
1.7o/o
1.60/o
1.60/0
1.60/o
1.6Yo
1.6%
't.6%
58,311
58,026
57,526
56,864
56,200
55,523
54,833
54,094
53,395
52,797
52,229
51,648
51,172
50,689
50,214
49,753
49,335
48,928
48,546
48,191
4,077
4,124
4,162
4,192
4,224
4,256
4,288
4,316
4,U5
4,378
4,409
4,436
4,470
4,501
4,531
4,560
4,593
4,627
4,663
4,701
2.0Yo
1.2Yo
0.9%
0.70/o
o.8%
0.8%
O.8o/o
o.6%
O.7o/o
O.8o/o
O.7o/o
O.60/o
O.8o/o
0.7%
0.7%
0.7%
0.7%
O.7o/o
0.8%
O.8o/o
466
471
475
477
482
486
490
492
496
500
503
505
510
514
517
519
525
528
533
535
Page44 20'17 lnlegrated Resource Plan
ldaho Power Company AppendixAl. Historicaland Projected Sales and Load
lrrigation Load
Historical lrrigation Sales and Load, 1976-2016 (weather adjusted)
Year
Maximum
Active
Customers
Percent
Ghange
kWh per
Customer
Percent
Change
Average
Load (aMW)
Billed Sales
(thousands of MWh)
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1 987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1 997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
20't2
20't3
2014
2015
2016
9,936
10,238
10,476
10,711
10,854
11,248
11,312
1 1,133
11,375
11,576
11,308
11,2il
11,378
11,957
12,v0
12,4U
12,809
13,078
13,559
13,679
14,O74
14,383
't4,695
14,912
15,253
15,522
15,840
16,020
16,297
16,936
17,062
17,OO1
17,428
17,708
't7,846
18,292
18,675
19,017
19,328
19,756
20,u2
3.OYo
2.3o/o
2.2%
1.3%
3.60/o
0.6%
-1.6%
2.2%
1.8o/o
-2.3%
-0.5%
1.1%
5.1o/o
3.2%
1.2%
2.6%
2.1o/o
3.7%
0.9%
2.9%
2.2%
2.2%
1.5%
2.3o/o
1.8%
2.O%
1.1o/o
1.7%
3.9o/o
0.7%
-o.4%
2.5%
1.6%
O.8o/o
2.5o/o
2.',|o/o
1.8o/o
1.60/o
2.2o/o
1.4o/o
157,590
163,580
1il,417
1U,233
160,661
167,476
154,133
't47,254
136,431
133,886
133,605
132,650
137,485
137,849
't49,397
138,862
141,889
131,086
't32,337
128,923
126,199
120,399
120,U0
120,589
128,659
't17,ffi1
109,186
111,786
109,191
102,141
96,870
105,2t66
109,423
101,814
101,998
99,885
104,064
103,977
104,762
95,595
96,320
1,566
1,675
1,618
't,759
1,744
1,884
1,744
1,639
'1,552
1,550
1,511
1,493
1,564
1,448
1,844
1,7U
1,817
1,714
1,794
1,764
1,776
1,732
1,768
1,798
1,962
1,825
1,730
1,791
'1,779
1,730
1,653
1,793
1,907
1,803
1,820
1,827
1,943
't,977
2,O25
1,889
1,930
7.0%
-3.4o/o
8.7o/o
-O.9Yo
8.OYo
-7.4o/o
-6.0%
-5.3Yo
-0jlo/o
-2.SYo
-1 .2o/o
4.8o/o
5.4o/o
11.8%
-6.0%
4.8o/o
-5.7o/o
4.7o/o
-1 .7o/o
O.7o/o
-2.SYo
2.1Yo
1.7o/o
9.1o/o
-7.0o/o
-5.2o/o
3.5%
-0.6%
-2.8o/o
4.5o/o
8.SYo
6.4o/o
-5.5o/o
1.0%
O.4o/o
6.4Yo
1.7o/o
2.4o/o
-6.7o/o
2.2o/o
178
191
185
201
199
215
199
187
177
177
172
170
178
188
210
198
207
196
205
20'l
202
198
202
205
223
208
197
204
203
197
189
205
2',t7
206
208
209
221
226
231
213
220
20'17 lntegrated Resource Plan Page 45
Appendix A1. Historical and Projected Sales and Load ldaho Power Company
Projected lrrigation Sales and Load, 2017-2036
Year
Maximum
Active
Customers
Percent
Change
kWh per
Customer
Billed Sales
(thousands of MWh)
Percent
Change
Average
Load (aMW)
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
203/.
2035
2036
20,322
20,623
20,914
21,2',t1
21,508
21,806
22,102
22,393
22,69',1
22,988
23,285
23,581
23,877
24,172
24,469
24,76
25,062
25,356
25,651
25,946
1.4o/o
1.5o/o
1.4o/o
1.4o/o
1.4o/o
'1.40/o
'1.40/o
1.3o/o
1.3o/o
1.3o/o
1.3Yo
1.3o/o
1.3o/o
1.2o/o
1.2Yo
1.2o/o
1.2o/o
1.2o/o
1.2o/o
1.2o/o
95,100
94,261
93,667
92,910
92,038
91,417
90,745
90,067
89,332
88,614
88,060
87,483
86,865
86,305
85,740
85,113
84,622
84,178
83,720
83,336
1,933
1,944
1,959
1,97',1
1,980
1,993
2,006
2,017
2,027
2,037
2,050
2,063
2,074
2,086
2,098
2,108
2,121
2,',tu
2,148
2,162
O.1Yo
O.6Yo
O.8o/o
0.6%o
O.4o/o
o.70/o
O.60/o
O.60/o
O.5o/o
O.SYo
O.7o/o
O.6Yo
o.5Yo
O.60/o
O.60/o
O.SYo
0.6%
0.6%
O.60/o
O.7o/o
221
222
224
224
226
228
229
230
231
233
2v
235
237
238
239
240
242
244
245
246
Page 46 2017 lntegrated Resource Plan
ldaho Power Company Appendix 41. Historical and Projected Sales and Load
lndustrial Load
Historical lndustrial Sales and Load, 1976-20{6 (not weather adjusted)
Year
Average
Customers
Percent
Change
kWh per
Customer
Percent
Change
Average
Load (aMW)
Billed Sales
(thousands of MWh)
1976
1977
1978
1979
1980
1981
1982
1 983
1984
1985
1986
1987
1 988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
73
85
99
109
112
118
122
't22
124
125
129
134
133
132
132
135
140
141
143
't20
103
106
111
108
107
111
't11
112
117
126
't27
123
119
't24
121
120
115
114
113
116
118
15.1o/o
17.60/o
9.60/o
2.7%
5.7o/o
3.5%
-0.3%
1.5%
1.2%
2.7o/o
4.1o/o
-'l.oo/o
-O.6Yo
o.2%
2.5%
3.4%
0.5%
1.7%
-15.9o/o
-14.40/o
2.7%
4.6%
-2.3o/o
-O.lYo
3.5%
-0.1o/o
1.O%
4.3%
7.9o/o
1.Oo/o
-3.60/o
-3.1o/o
4.Oo/o
-2.0o/o
-1 .1o/o
4.2o/o
-O.7o/o
-O.7o/o
2.8o/o
1-4o/o
858
929
972
1,087
1,106
1,148
1,162
1,194
1,282
1,357
1,357
1,474
1,546
1,594
1,662
1,719
1,770
1,854
1,948
2,021
1,934
2,O42
2,145
2,160
2,191
2,289
2,156
2,234
2,269
2,351
2,325
2,366
2,308
2,224
2,232
2,230
2,271
2,314
2,363
2,360
2,361
8.3o/o
4.7o/o
11.8o/o
1.7%
3.9o/o
1.2%
2.7o/o
7.4%
5.9o/o
-o.10/o
8.7%
4.9o/o
3.1o/o
4.3o/o
3.4o/o
3.OYo
4.7%
5.1o/o
3.7o/o
4.3o/o
5.6%
5.Oo/o
0.7%
15%
4A%
-5.8%
3.6%
1.5%
3.6%
-1.1%
1.8o/o
-2.4%
-3.6%
0.3%
-0.1o/o
1.8o/o
1.9o/o
2.1o/o
-O.1o/o
0.1o/o
99
106
111
126
125
132
133
138
147
155
155
169
177
183
191
196
203
212
223
230
221
235
244
247
250
260
246
255
259
270
265
270
261
254
254
254
258
265
271
269
270
11,681,540
10,988,826
9,786,753
9,989,158
9,894,706
9,718,723
9,504,283
9,797,522
10,369,789
10,844,888
10,550,145
11,006,455
11,660,183
12,091,482
12,584,200
12,699,665
12,650,945
13,179,585
13,616,608
16,793,437
18,774,O93
19,309,504
19,378,7U
19,985,029
20,433,299
20,618,361
19,441,876
19,950,866
19,417,310
18,645,220
18,255,385
19,275,551
19,412,391
17,987,570
18,404,875
18,597,050
19,757,921
20,28',t,837
20,863,653
20,271,082
19,997,106
2017 lntegrated Resource Plan Page 47
Appendix 41. Historical and Projected Sales and Load ldaho Power Company
Projected lndustrial Sales and Load, 2017-2036
Year
Average
Customers
Percent
Change
kWh per
Customer
Percent
Change
Average
Load (aMW)
Billed Sales
(thousands of MWh)
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
119
120
121
121
121
122
'123
124
125
125
127
128
128
128
129
130
130
131
133
133
O.8o/o
O.8o/o
O.8o/o
O.OYo
O.OYo
0.80/o
O.8o/o
O.8o/o
0.8%
0.0%
1.6%
0.8o/o
0.0%
O.Oo/o
0.8%
0.8%
O.Oo/o
O.$Yo
1.5o/o
O.Oo/o
2,452
2,524
2,561
2,586
2,601
2,614
2,629
2,U4
2,657
2,669
2,683
2,699
2,7',t5
2,730
2,746
2,759
2,772
2,786
2,800
2,814
3.8o/o
2.9o/o
1.4o/o
1.0%
0.6%
O.5o/o
O.60/0
o.50/o
O.5Yo
O.5o/o
O.5o/o
O.60/0
0.6%
O.60/o
O.60/0
0.50h
o.5%
O.5o/o
o.5%
O.5o/o
28',1
288
293
295
297
299
300
301
303
305
306
307
310
312
314
314
317
318
320
320
20,602,815
21.033,767
21,161,810
21,372,860
21,497,289
21,426,910
21,375,415
21,3'18,605
21,253,784
21,355,032
21,',t24,323
21,082,969
21,208,625
21,329,641
21,284,186
21,226,438
21.325,215
21,268,565
21,Oil,677
21,155,835
Page 48 2017 lntegrated Resource Plan
ldaho Power Company Apoendix A1. Historical and Proiected Sales and Load
Additional Firm Sales and Load
Historical Additional Firm Sales and Load,1976-2016
Year
Billed Sales
(thousands of MWh) Percent Change Average Load (aMW)
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1 989
1990
1991
1992
1993
1994
1995
1996
1 997
1998
1999
2000
2001
2002
2003
200/r
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
288
311
357
373
360
376
367
425
466
471
482
502
530
671
625
661
680
689
740
878
989
1,048
1,113
1,121
1,',143
1,118
1,139
1j20
1,156
1,175
1,189
1,141
1,114
965
907
906
862
867
841
842
870
7.8o/o
14.8o/o
4.4o/o
-3.5o/o
4.60/o
-2.40/o
15.7o/o
9.7o/o
'l .10/o
2.4o/o
4.2o/o
5.6Yo
26.5%
-6.9o/o
5.8o/o
2.9Yo
1.3o/o
7.5o/o
18.6%
12.6%
6.0%
6.20/o
O.8Yo
1.9Vo
-2.1o/o
1.9o/o
-1 .7o/o
3.3Yo
1.6Yo
1.2o/o
4.O%
-2.4%
-13.4o/o
-6.Oo/o
o.o%
4.8o/o
0.5%
-2.9%
o1%
3.3%
33
35
41
43
41
43
42
49
53
54
55
57
60
77
71
75
77
79
85
100
113
120
127
128
130
128
130
128
132
1U
136
130
127
't 10
103
103
98
99
96
96
99
*lncludes Micron Technology, Simplot Fertilizer, lNL, Hoku Materials, City of Weiser,
and Raft River Rural Eleciric Cooperative, lnc.
2017 lntegrated Resource Plan Page 49
Appendix A1. Historical and Projected Sales and Load ldaho Power Company
Projected Additional Firm Sales and Load, 2017-2036
Year
Billed Sales
(thousands of MWh)Percent Change Average Load (aMW)
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
945
962
972
979
983
990
1,011
1,084
1,086
1,086
1,087
1,089
1,088
1,088
1,088
1,089
1,090
1,090
1,092
1,O92
8.60/o
1.7o/o
1.1o/o
O.7o/o
O.4o/o
0.8%o
2.10/o
7.2%
O.2o/o
-O.1Yo
O.1o/o
O.2o/o
-0.10h
O.Oo/o
o.oo/o
O.1o/o
O.1o/o
o.006
O.2o/o
O.Oo/o
108
110
111
't11
112
113
115
123
124
124
124
124
124
124
124
124
124
124
125
124
*lncludes Micron Technology, Simplot Fertilizer, and the INL
Page 50 2017 lntegrated Resource Plan
ldaho Power Company Aooendix A1. Historicaland Proiected Sales and Load
Company System Load (excluding Astaris)
Historical Company System Sales and Load, 1976-2016 (weather adjusted)
Billed Sales
(thousands of MWh)Percent Ghange Average Load (aMW)Year
1976
1977
1978
1979
1980
1981
1982
1983
1984
'1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
't998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
6,413
6,778
7,242
7,624
7,842
8,129
7,84',1
8,019
8,125
8,285
8,341
8,478
8,814
9,209
9,568
9,756
9,990
10,235
10,657
11,062
11,414
11,746
12,2',11
12,491
12,911
13,050
12,748
13,053
13,327
13,618
13,910
14,339
14,449
13,961
13,812
13,822
14,007
14,060
14,232
14,0U
14,231
5.70/o
6.$Yo
5.3Yo
2.80/o
3.7Yo
-3.50/o
2.30/o
1.3o/o
2.0o/o
0.7%
1.6Yo
4.O%
4.5%
3.9Yo
2.Oo/o
2.4%
2.5o/o
4.1o/o
3.8o/o
3.2Yo
2.9Yo
4.Oo/o
2.3Yo
3.4o/o
1.1o/o
-2.30/o
2.4o/o
2.10/o
2.2o/o
2.2o/o
3.10/o
O.8o/o
-3.40/o
-1.1o/o
O.1o/o
1.30/o
O.4o/o
1.2o/o
-1 .2o/o
1.2o/o
799
848
899
955
971
1,009
976
997
1,007
1,030
1,034
't,053
1,O92
1,143
1,190
1,209
1,238
1,270
1,324
1,371
1,413
1,458
1,513
'1,548
1,599
1,613
1,580
1,618
1,651
1,692
1,725
1,779
1,784
1,732
1,712
1,7'.13
1,732
1,750
1,763
1,742
1,762
2017 lntegrated Resource Plan Page 51
Appendix A1. Historical and Projected Sales and Load ldaho Power Company
Company System Load
Projected Company System Sales and Load, 2017-2036
Year
Billed Sales
(thousands of MWh)Percent Change Average Load (aMW)
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
14,598
14,842
15,0/41
15,161
15,282
15,442
15,615
15,824
15,941
16,059
16,196
16,329
16r'.il
16,570
16,680
16,779
16,903
17,O37
17,175
17,326
2.6%
1.7%
1.3%
o.8%
O.8o/o
't.oYo
1.1o/o
1.3Yo
O.7Yo
O.7o/o
O.9o/o
O.8o/o
O.$Yo
O.7o/o
O.7o/o
O.60/o
O.7o/o
O.8o/o
O.8o/o
0.9%
1,810
1,840
1,864
1,874
1,894
1,914
1,935
1,955
1,975
1,990
2,007
2,O18
2,039
2,053
2,067
2,O74
2,095
2,112
2,',t29
2,142
Page 52 2017 lntegrated Resource Plan