20150630IRP Appendix A Sales and Load Forecast .pdf

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SAFE HARBOR STATEMENT
This document may contain forward-looking statements, and it is important to note that the future
results could differ materially from those discussed. A full discussion of the factors that could cause
future results to differ materially can be found in Idaho Power’s filings with the Securities and
Exchange Commission.
ACKNOWLEDGMENT
Resource planning is an ongoing process at Idaho Power. Idaho Power
prepares, files, and publishes an Integrated Resource Plan every two years.
Idaho Power expects that the experience gained over the next few years will
likely modify the 20-year resource plan presented in this document.
Idaho Power invited outside participation to help develop the 2015
Integrated Resource Plan. Idaho Power values the knowledgeable
input, comments, and discussion provided by the Integrated Resource
Plan Advisory Council and other concerned citizens and customers.
It takes approximately one year for a dedicated team of individuals at Idaho
Power to prepare the Integrated Resource Plan. The Idaho Power team is
comprised o f individuals t hat represent m any different d epartments within
the company. The Integrated Resource Plan team members are responsible
for preparing forecasts, working with the advisory council and the public,
and performing all the analyses necessary to prepare the resource plan.
Idaho Power looks forward to continuing the resource planning process with
customers, public interest groups, regulatory agencies, and other interested
parties. You can learn more about the Idaho Power resource planning
process at www.idahopower.com.
2015
IntegratedResourcePlan
Sales and Load ForecastAPPENDIX A
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June 2015

Idaho Power Company Appendix A—Sales and Load Forecast
2015 Integrated Resource Plan Page i
TABLE OF CONTENTS
Table of Contents ............................................................................................................................. i
List of Tables .................................................................................................................................. ii
List of Figures ................................................................................................................................. ii
List of Appendices ......................................................................................................................... iii
Introduction ......................................................................................................................................1
2015 IRP Sales and Load Forecast ..................................................................................................3
Average Load .............................................................................................................................3
Peak-Hour Demands ..................................................................................................................4
Overview of the Forecast .................................................................................................................7
Fuel Prices ..................................................................................................................................8
Electric Vehicles ......................................................................................................................10
Forecast Probabilities ...............................................................................................................11
Load Forecasts Based on Weather Variability...................................................................11
Load Forecasts Based on Economic Uncertainty ..............................................................12
Residential......................................................................................................................................15
Commercial ....................................................................................................................................17
Irrigation ........................................................................................................................................21
Industrial ........................................................................................................................................23
Additional Firm Load ....................................................................................................................25
Micron Technology ..................................................................................................................26
Simplot Fertilizer .....................................................................................................................26
Idaho National Laboratory .......................................................................................................26
Company System Peak ..................................................................................................................27
Company System Load ..................................................................................................................29
Contract Off-System Load .............................................................................................................31
Energy Efficiency and Demand Response .....................................................................................33
Energy Efficiency ....................................................................................................................33
Demand Response ....................................................................................................................34
Appendix A—Sales and Load Forecast Idaho Power Company
Page ii 2015 Integrated Resource Plan
LIST OF TABLES
Table 1. Residential fuel-price escalation (2015–2034) (average annual
percent change) ..............................................................................................................8
Table 2. Average load and peak-demand forecast scenarios .....................................................12
Table 3. Forecast probabilities ...................................................................................................13
Table 4. System load growth (aMW) .........................................................................................14
Table 5. Residential load growth (aMW)...................................................................................15
Table 6. Commercial load growth (aMW) .................................................................................17
Table 7. Irrigation load growth (aMW) .....................................................................................21
Table 8. Industrial load growth (aMW) .....................................................................................23
Table 9. Additional firm load growth (aMW) ............................................................................25
Table 10. System summer peak load growth (MW) ....................................................................27
Table 11. System winter peak load growth (MW) .......................................................................28
Table 12. System load growth (aMW) .........................................................................................29

LIST OF FIGURES
Figure 1. Forecast residential electricity prices (cents per kWh) ..................................................9
Figure 2. Forecast residential natural gas prices (dollars per therm) ..........................................10
Figure 3. Forecast system load (aMW) .......................................................................................14
Figure 4. Forecast residential load (aMW) ..................................................................................15
Figure 5. Forecast residential use per customer (weather-adjusted kWh) ..................................16
Figure 6. Forecast commercial load (aMW) ...............................................................................17
Figure 7. Commercial building share ..........................................................................................18
Figure 8. Forecast commercial use per customer (weather-adjusted kWh) ................................19
Figure 9. Commercial categories UPC, 2014 relative to 2010 ....................................................19
Figure 10. Forecast irrigation load (aMW) ...................................................................................21
Figure 11. Forecast industrial load (aMW) ...................................................................................23
Figure 12. Industrial electricity consumption by industry group (based on 2014 sales)...............24
Figure 13. Forecast additional firm load (aMW) ..........................................................................25
Figure 14. Forecast system summer peak (MW) ..........................................................................27
Figure 15. Forecast system winter peak (MW) .............................................................................28
Idaho Power Company Appendix A—Sales and Load Forecast
2015 Integrated Resource Plan Page iii
Figure 16. Forecast system load (aMW) .......................................................................................29
Figure 17. Composition of system company electricity sales (thousands of MWh) .....................30

LIST OF APPENDICES
Appendix A1. Historical and Projected Sales and Load .............................................................35
Residential Load ......................................................................................................................35
Historical Residential Sales and Load, 1974–2014 (weather adjusted) .............................35
Projected Residential Sales and Load, 2015–2034 ............................................................36
Commercial Load.....................................................................................................................37
Historical Commercial Sales and Load, 1974–2014 (weather adjusted) ...........................37
Projected Commercial Sales and Load, 2015–2034 ..........................................................38
Irrigation Load .........................................................................................................................39
Historical Irrigation Sales and Load, 1974–2014 (weather adjusted) ................................39
Projected Irrigation Sales and Load, 2015–2034 ...............................................................40
Industrial Load .........................................................................................................................41
Historical Industrial Sales and Load, 1974–2014 (not weather adjusted) .........................41
Projected Industrial Sales and Load, 2015–2034 ...............................................................42
Additional Firm Sales and Load* ............................................................................................43
Historical Additional Firm Sales and Load, 1974–2014 ...................................................43
Projected Additional Firm Sales and Load, 2015–2034 ....................................................44
Company System Load (excluding Astaris) ............................................................................45
Historical Company System Sales and Load, 1974–2014 (weather adjusted) ..................45
Projected Company System Sales and Load, 2015–2034 ..................................................46
Appendix A—Sales and Load Forecast Idaho Power Company
Page iv 2015 Integrated Resource Plan
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Idaho Power Company Appendix A—Sales and Load Forecast
2015 Integrated Resource Plan Page 1
INTRODUCTION
Idaho Power has prepared Appendix A—Sales and Load Forecast as part of the 2015 Integrated Resource Plan (IRP). The sales and load forecast is Idaho Power’s best estimate of the future demand for electricity within the company’s service area. The forecast covers the 20-year period from 2015 through 2034.
The expected-case monthly average load forecast represents Idaho Power’s estimate of the most
probable outcome for load growth during the planning period and is based on the most recent
economic forecast for Idaho Power’s service area. To account for inherent uncertainty and variability, four additional load forecasts were prepared—two that provide a range of possible load growths due to economic uncertainty and two that address the load variability associated
with abnormal weather. 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. The high-growth and low-growth scenarios were prepared based on statistical analyses to empirically reflect uncertainty inherent in the load forecast. The 70th-percentile and 90th-percentile load forecast scenarios were developed to assist
Idaho Power in reviewing the resource requirements that would result from higher loads due to
more adverse weather conditions.
While the expected-case load forecast assumes median historical values (50th percentile) for temperatures and median rainfall, the weather scenarios are developed with a 70th-percentile and a 90th-percentile weather probability assumption. The 70th-percentile load forecast assumes
monthly loads that can be exceeded in 3 out of 10 years (30% of the time). The 90th-percentile
load forecast assumes monthly loads that can be exceeded in 1 out of 10 years (10% of the time).
Idaho Power uses the 70th-percentile load forecast in IRP resource planning 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
2,240 average megawatts (aMW) by 2034 from 1,786 aMW in 2015, representing an average
yearly growth rate of 1.2 percent over the 20-year planning period (2015–2034). In the more
critical 70th-percentile load forecast used for resource planning, the system load is forecast to reach 2,292 aMW by 2034 (1.2% average annual growth).
The Idaho Power system peak load (95th percentile) is forecast to grow to 4,773 megawatts
(MW) in 2034 from the actual system summer peak of 3,407 MW that occurred on Tuesday,
July 2, 2013, at 4:00 p.m. In the expected-case scenario, the Idaho Power system peak increases
at an average growth rate of 1.5 percent per year over the 20-year planning period (2015–2034).
This year’s economic forecast was based on a forecast of national and regional economic activity developed by Moody’s Analytics, Inc. The national, state, metropolitan statistical area
(MSA) and county econometric projections are tailored to Idaho Power’s service area using an
in-house economic forecast model and database. Specific demographic projections are also
developed for the service area from national and local census data. National economic drivers from Moody’s Analytics were also used in the development of Appendix A—Sales and Load Forecast. The number of Idaho Power active retail customers is expected to increase from the
December 2014 level of 514,700 customers to nearly 710,000 customers by year-end 2034.
Appendix A—Sales and Load Forecast Idaho Power Company
Page 2 2015 Integrated Resource Plan
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 1.9 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. 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 2014 Annual Report, which is
incorporated into this IRP document as Appendix B.
During the 20-year forecast horizon, major changes in the electric utility industry
(e.g., carbon regulations and subsequent higher electricity prices impacting future electricity
demand) 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 impact of carbon legislation on the load forecast is reflected
in the retail electricity price variable for each forecasted customer sector. The alternative 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.

Idaho Power Company Appendix A—Sales and Load Forecast
2015 Integrated Resource Plan Page 3
2015 IRP SALES AND LOAD FORECAST
Average Load
The 2015 IRP average annual system load forecast reflects the continued improvement in the
service area economy. While economic conditions during the development of the 2013 IRP were
positive, they were less optimistic than the actual performance experienced in the interim period
leading up to the 2015 IRP. The improved economic and demographic variables driving the
2015 forecast are reflected by a more positive sales outlook throughout the planning period. The stalled recovery in the national and, to a lesser extent, service-area economy caused load
growth to stall through 2011. However, in 2012, the recovery was evident, with strength
exhibited in most all economic drivers to date. Retail electricity price projections for the 2015
IRP are lower relative to the 2013 IRP, serving to increase the forecast of average loads,
especially in the second 10 years of the forecast period.
Significant factors and considerations that influenced the outcome of the 2015 IRP load forecast
include the following:
• The load forecast used for the 2015 IRP reflects a near-term recovery in the service-area
economy following a severe recession in 2008 and 2009 that kept sales from growing through 2011. The collapse in the housing sector beginning in 2008 held new
construction and customer growth to a near standstill until 2012. However, beginning in
2012, acceleration of in-migration and business investment resulted in renewed growth in
the residential and commercial connections along with increased industrial activity. By 2017, customer additions are forecast to approach sustainable growth rates experienced prior to the housing bubble (2000–2004).
• The electricity price forecast used to prepare the sales and load forecast in the 2015 IRP
reflects the impact of additional plant investment and associated variable costs of
integrating new resources identified in the 2013 IRP preferred portfolio, including the expected costs of carbon emissions. As discussed previously, when compared to the
electricity price forecast used to prepare the 2013 IRP sales and load forecast,
the 2015 IRP price forecast yields lower future prices. The retail prices are most
evident 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.
• 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 commitment 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 commitments are not included in the current sales and
load forecast.
Appendix A—Sales and Load Forecast Idaho Power Company
Page 4 2015 Integrated Resource Plan
• Conservation impacts, including DSM energy efficiency programs and codes and
standards, 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 2015 irrigation sales forecast is higher than the 2013 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 taken
advantage of higher market prices over the past few years and 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
Peak-day temperatures and the growth in average loads drive the peak forecasting model regressions. The peak forecast results and comparisons with previous forecasts differ for a
number of reasons that include the following:
• The 2015 IRP peak-demand forecast considers the impact of committed and implemented
energy efficiency DSM programs on peak demand.
• The 2015 IRP peak-demand forecast model explicitly excludes the impact of demand
response programs 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.
• The peak model develops peak-scenario impacts based on historical probabilities of
peak-day temperatures at the 50th, 90th, and 95th percentiles of occurrence for each month
of the year.
• The all-time system summer peak demand was 3,407 MW (recorded on Tuesday, July 2, 2013, at 4:00 p.m.) and serves as a benchmark for the forecasting model. The previous
summer peak demand was 3,245 MW, occurring on Thursday, July 12, 2012, at 4:00 p.m.
Historical peak-demand data serve as the basis in the peak-model regressions.
Historical new peak loads were reached in July 2007, June 2008, July 2012, and July 2013.
• The summer system peak load growth accelerated from 1998 to 2008 as a record
number of residential and commercial 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 Company Appendix A—Sales and Load Forecast
2015 Integrated Resource Plan Page 5
• Idaho 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. Peak-day temperatures are not normally distributed and can be skewed by one or more extreme observations as referred to in the previous bulleted item; 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 1984 to 2013 time period
(the most recent 30 years).
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Idaho Power Company Appendix A—Sales and Load Forecast
2015 Integrated Resource Plan Page 7
OVERVIEW OF THE FORECAST
The sales and load forecast is constructed by developing a separate forecast for each of the
major customer classes: residential, commercial, irrigation, and industrial. Individual energy and peak-demand forecasts are developed for special-contract customers, including Micron Technology, Inc.; Simplot Fertilizer Company (Simplot Fertilizer); and the Idaho National
Laboratory (INL). These three special-contract customers are reported as a single forecast
category labeled additional firm load. Currently, Idaho Power has no long-term contracts to
provide off-system customers with firm energy and demand. The assumptions for each of the individual categories are described in greater detail in the respective sections.
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 department. The annual
average energy loss coefficients 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 loss coefficients are lower than those
applied to the 2013 IRP generation forecast. This resulted in a permanent reduction of nearly
20 aMW to the load forecast annually.
The peak-load forecast was prepared in conjunction with the 2015 sales forecast. Idaho Power has two peak periods: 1) a winter peak, resulting primarily from space-heating demand that normally occurs in December, January, or February and 2) a larger summer peak that normally
occurs in late June or July. The summer peak generally occurs when extensive A/C use coincides
with significant irrigation demand.
Peak loads are forecast using 12 regression equations and are a function of average peak-day temperatures, the historical monthly average load, and precipitation (summer only). The peak forecast uses statistically derived peak-day temperatures based on the most recent
30 years of climate data for each month. Peak loads for the INL, Micron Technology,
and Simplot Fertilizer are forecast based on a historical analysis, customer-provided input,
and any contractual considerations.
The primary external factors influencing the forecast are economic and demographic in nature. Moody’s Analytics serves as the primary provider for this data. The national, state, 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. Additional data sources used to substantiate Moody’s data include the Idaho Department of Labor, Construction Monitor, and Federal Reserve Economic Databases.
Appendix A—Sales and Load Forecast Idaho Power Company
Page 8 2015 Integrated Resource Plan
Fuel 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 have
significant impacts on the future demand for electricity. The sales and load forecast is also
influenced by the estimated impact of proposed carbon legislation on retail electricity prices.
In addition to supply-side influences, carbon-reduction legislation creates an upward trend in
retail electricity prices throughout the forecast period, resulting in reduced future electricity sales. Class-level and economic-sector-level regression models were used to identify 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 internally from Idaho Power financial models. The United States (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 at real fuel prices. The projected average annual growth rates of fuel prices in nominal
and real terms (adjusted for inflation) are presented in Table 1. 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 1. Residential fuel-price escalation (2015–2034) (average annual percent change)
Nominal Real*
Electricity—2015 IRP ................................................................................................1.9% 0.0%
Electricity—2013 IRP ................................................................................................2.9% 1.0%
Natural Gas ................................................................................................................................3.2% 1.3%
* Adjusted for inflation

Figure 1 illustrates the average electricity price paid by Idaho Power’s residential customers over
the historical period 1979 to 2014 and over the forecast period 2015 to 2034. Both nominal and
real prices are shown. In the 2015 IRP, nominal electricity prices are expected to climb to about 14 cents per kilowatt-hour (kWh) by the end of the forecast period in 2034. Real electricity
prices (inflation adjusted) are expected to remain flat over the forecast period at an average rate
of 0.0 percent annually. In the 2013 IRP, nominal electricity prices were assumed to climb to
about 18 cents per kWh by 2034, and real electricity prices (inflation adjusted) were expected to
slowly increase over the forecast period at an average rate of 1.0 percent annually. The impact of the lower real electricity price forecast on the 2015 IRP load forecast serves to positively
influence the growth in electricity sales, especially in the last 10 years of the forecast period.
The electricity price forecast used to prepare the sales and load forecast in the 2015 IRP reflected
the additional plant investment and variable costs of integrating the resources identified in the 2013 IRP preferred portfolio, including the expected costs of carbon emissions. When compared to the electricity price forecast used to prepare the 2013 IRP sales and load forecast, the 2015
IRP price forecast yielded lower future prices. The retail prices are more evidently lower in the
Idaho Power Company Appendix A—Sales and Load Forecast
2015 Integrated Resource Plan Page 9
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.

Figure 1. Forecast residential electricity prices (cents per kWh)
Electricity prices for Idaho Power customers increased significantly in 2001 and 2002 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 2001, Idaho Power’s electricity prices were historically quite stable.
From 1990 to 2000, electricity prices rose only 8 percent overall, an annual average compound
growth rate of 0.8 percent annually.
Figure 2 illustrates the average natural gas price paid by Intermountain Gas Company’s
residential customers over the historical period 1979 to 2013 and forecast prices from 2014 to 2034. 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 in 2004 through 2006. Since 2006, natural gas prices have
experienced a steady decline, matching prices from over a decade ago. Nominal natural gas
prices are expected to remain flat through 2017, then rise at a steady pace throughout the remainder of the forecast period until nearly doubling by 2034, growing at an average rate of
3.2 percent per year. Real natural gas prices (adjusted for inflation) are expected to increase over
the same period at an average rate of 1.3 percent annually.
0
2
4
6
8
10
12
14
16
18
20
1979 1984 1989 1994 1999 2004 2009 2014 2019 2024 2029 2034
Nominal Real Nominal—2013 IRP
Nominal—2015 IRP Real—2013 IRP Real—2015 IRP
Hi
Appendix A—Sales and Load Forecast Idaho Power Company
Page 10 2015 Integrated Resource Plan
Figure 2. 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 2015 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, such limiting attributes of vehicle range and
re-fueling time continue to improve the competiveness 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 names (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, sufficient service-area data became 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 Department of Energy’s
(DOE) National Energy Model (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.
$0.00
$0.20
$0.40
$0.60
$0.80
$1.00
$1.20
$1.40
$1.60
$1.80
1979 1984 1989 1994 1999 2004 2009 2014 2019 2024 2029 2034
Nominal Actual Nominal Forecast Real Actual Real Forecast
Idaho Power Company Appendix A—Sales and Load Forecast
2015 Integrated Resource Plan Page 11
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 this 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
2013 IRP model and more on third-party assumptions, as was the case in earlier forecasts.
Forecast Probabilities
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 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 from Moody’s Analytics and the resulting derived economic forecast for Idaho Power’s service area.
The expected-case load forecast assumes median temperatures and median precipitation
(i.e., there is a 50-percent 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, two alternative scenarios were considered that address load variability
due to weather.
Maximum 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 load occurs when the lowest recorded levels of HDD are
assumed in winter and the lowest recorded levels of CDD and GDD, combined with the highest
level of precipitation, are assumed in summer.
For example, at the Boise Weather Service office, the median HDD in December from 1984 to 2013 (the most recent 30 years) was 1,039. The 70th-percentile HDD is 1,074 and would be exceeded in 3 out of 10 years. The 90th-percentile HDD is 1,268 and would be exceeded in 1 out
of 10 years. The 100th-percentile HDD (the coldest December over the 30 years) is 1,619 and
occurred in December 1985. This same concept was applied in each month throughout the year
in only the weather-sensitive customer classes: residential, commercial, and irrigation.
In the 70th-percentile residential and commercial load forecasts, temperatures in each month were
assumed to be at the 70th percentile of HDD in wintertime and at the 70th 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 30th percentile, reflecting drier-than-median weather.
The 90th-percentile load forecast was similarly constructed.
Appendix A—Sales and Load Forecast Idaho Power Company
Page 12 2015 Integrated Resource Plan
Idaho Power loads are highly dependent on weather, and these two scenarios allow 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 any
given month. To assume temperatures and precipitation would maintain a 70th-percentile or 90th-percentile level continuously, month after month throughout an entire year, would be much
less probable. Monthly forecast numbers are evaluated for resource planning, and caution should
be used in interpreting the meaning of the annual average load figures being reported and
graphed for the 70th-percentile or 90th-percentile forecasts.
Table 2 summarizes the load scenarios prepared for the 2015 IRP. Three average load scenarios were prepared based on a statistical analysis of the historical monthly weather variables listed.
The probability associated with each average load scenario is also indicated in the table.
In addition, three peak-demand scenarios were prepared based on a statistical analysis of
historical peak-day average temperatures, and the probability associated with each peak-demand
scenario is also indicated in Table 2.
Table 2. Average load and peak-demand forecast scenarios
Scenario Weather Probability Probability of Exceeding Weather Driver
Forecasts of Average Load
90th Percentile 90% 1 in 10 years HDD, CDD, GDD, precipitation
70th Percentile 70% 3 in 10 years HDD, CDD, GDD, precipitation
Expected Case 50% 1 in 2 years HDD, CDD, GDD, precipitation
Forecasts of Peak Demand
95th Percentile 95% 1 in 20 years Peak-day temperatures
90th Percentile 90% 1 in 10 years Peak-day temperatures
50th Percentile 50% 1 in 2 years Peak-day temperatures
The analysis of resource requirements is based on the 70th-percentile average load forecast
coupled with the 95th-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 90th-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. The forecasts provide a range of possible load growths for the 2015 to 2034 planning period due to high and low economic and demographic conditions.
The high and low economic-growth scenarios were prepared based on a statistical analysis to
empirically reflect the uncertainty inherent in the load forecast. The average growth rates for the
high and low growth scenarios were derived from the historical distribution of one-year growth rates over the past 25 years (1990–2014).
Idaho Power Company Appendix A—Sales and Load Forecast
2015 Integrated Resource Plan Page 13
The estimated probabilities for the three load scenarios are reported in Table 2. The standard
deviation observed during the historical time period is used to estimate the dispersion around the expected-case scenario. The probability estimates assume the expected forecast is the median
growth path (i.e., there is a 50-percent probability the actual growth rate will be less than the
expected-case growth rate and a 50-percent chance the actual growth rate will be greater than
the expected-case growth rate). In addition, the probability estimates assume the variation in
growth rates will be equivalent to the variation in growth rates observed over the past 25 years (1990–2014).
Two views of probable outcomes from the forecast scenarios—the probability of exceeding and
the probability of occurrenceare—are reported in Table 3. The probability of exceeding shows 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 10-percent probability the actual growth rate will exceed the growth rate projected in the high scenario; conversely, there is a 10-percent chance the actual growth rate will fall below that of the low scenario. In other words, over a
20-year period, there is an 80-percent probability the actual growth rate of system load will fall
between the growth rates projected in the high and low 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 otherscenario. For example, there is a 26-percent probability the actual growth rate will be closer to
the high scenario than to any other forecast scenario for the entire 20-year planning horizon.
Probabilities for shorter, 1-year, 5-year, and 10-year time periods are also shown in Table 3.
Table 3. Forecast probabilities
Probability of Exceeding
Scenario 1-year 5-year 10-year 20-year
Low Growth .................................................................................................90% 90% 90% 90%
Expected Case ............................................................................................50% 50% 50% 50%
High Growth ................................................................................................10% 10% 10% 10%
Probability of Occurrence
Scenario 1-year 5-year 10-year 20-year
Low Growth .................................................................................................26% 26% 26% 26%
Expected Case ............................................................................................48% 48% 48% 48%
High Growth ................................................................................................26% 26% 26% 26%
The 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, Inc.)
and on-system contracts (including past sales to Raft River Coop and the City of Weiser).
Idaho Power system load projections are reported in Table 4 and shown in Figure 3. The expected-case system load-forecast growth rate averages 1.1 percent per year over the
20-year planning period. The low scenario projects that the system load will increase at an
average rate of 0.7 percent per year throughout the forecast period. The high scenario projects a
load growth of 1.6 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.
Appendix A—Sales and Load Forecast Idaho Power Company
Page 14 2015 Integrated Resource Plan
Table 4. System load growth (aMW)
Growth 2015 2019 2024 2034
Annual Growth Rate
2015–2034
Low .......................................................................1,776 1,802 1,871 2,012 0.7%
Expected ...............................................................1,786 1,900 2,012 2,240 1.2%
High ......................................................................1,864 2,009 2,181 2,500 1.6%
Figure 3. Forecast system load (aMW)
800
1,000
1,200
1,400
1,600
1,800
2,000
2,200
2,400
2,600
2,800
1984 1989 1994 1999 2004 2009 2014 2019 2024 2029 2034
Weather Adjusted (excluding Astaris)Expected 70th Percentile High Low
Idaho Power Company Appendix A—Sales and Load Forecast
2015 Integrated Resource Plan Page 15
RESIDENTIAL
The expected-case residential load is forecast to increase from 588 aMW in 2015 to 755 aMW in
2034, an average annual compound growth rate of 1.3 percent. In the 70th-percentile scenario, the residential load is forecast to increase from 608 aMW in 2015 to 780 aMW in 2034, matching the expected-case residential growth rate. The residential load forecasts are reported
in Table 5 and shown in Figure 4.
Table 5. Residential load growth (aMW)
Growth 2015 2019 2024 2034
Annual Growth Rate
2015–2034
90 Percentile ................................................................643 689 730 825 1.3%
70 Percentile ................................................................608 651 689 780 1.3%
Expected Case ................................588 629 666 755 1.3%
Figure 4. Forecast residential load (aMW)
Sales to residential customers made up 32 percent of Idaho Power’s system sales in 1984 and
36 percent of system sales in 2014. The residential customer proportion of system sales is forecast to be approximately 37 percent in 2034. The number of residential customers is
projected to increase to approximately 591,000 by December 2034.
The average sales per residential customer increased to over 14,800 kWh in 1979 before
declining to 13,200 kWh in 2001. In 2002 and 2003, residential use per customer dropped
dramatically—over 500 kWh per customer from 2001—the result of two years of significantly higher electricity prices 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
0
100
200
300
400
500
600
700
800
900
1,000
1979 1984 1989 1994 1999 2004 2009 2014 2019 2024 2029 2034
Weather Adjusted Expected Case 70th Percentile 90th Percentile
Appendix A—Sales and Load Forecast Idaho Power Company
Page 16 2015 Integrated Resource Plan
use per customer to stabilize and rise through 2007. However, the recession in 2008 and 2009,
combined with conservation programs designed to reduce electricity use, slowed the growth in
residential use per customer. The average sales per residential customer are expected to slowly
decline to approximately 11,200 kWh per year in 2034. Average annual sales per residential customer are shown in Figure 5.
Figure 5. Forecast residential use per customer (weather-adjusted kWh)
The residential-use-per-customer forecast is based on a forecast of the number of residential
customers and an econometric analysis of residential-sector sales. The number of residential
customers being added each year is a direct function of the number of new service-area households as derived from Moody’s Analytics’ July 2014 forecast of county housing stock and demographic data. The residential-customer forecast for 2015 to 2034 shows an average annual
growth rate of 1.6 percent.
The residential sales forecast equation 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 as derived from Moody’s Analytics’ forecasts of county
housing stock; the real price of electricity; and the real price of natural gas. The forecast of
residential use per customer is arrived at by dividing the residential sales forecast,
which considers the impact of forecast DSM, by the residential-customer forecast.
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
20,000
1979 1984 1989 1994 1999 2004 2009 2014 2019 2024 2029 2034
Actual Forecast
Hi
Idaho Power Company Appendix A—Sales and Load Forecast
2015 Integrated Resource Plan Page 17
COMMERCIAL
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.
In total, within the expected-case scenario, the commercial load is projected to increase from
466 aMW in 2015 to 559 aMW in 2034. The average annual compound-growth rate of the
commercial load is 1.0 percent during the forecast period. As summarized in Table 6, the
commercial load in the 70th-percentile scenario is projected to increase from 472 aMW in 2015 to 568 aMW in 2034. The commercial load forecasts are illustrated in Figure 6.
Table 6. Commercial load growth (aMW)
Growth 2015 2019 2024 2034
Annual Growth Rate
2015–2034
90 Percentile ................................................................483 504 529 583 1.0%
70 Percentile ................................................................472 492 516 568 1.0%
Expected Case ................................................................466 485 509 559 1.0%

Figure 6. Forecast commercial load (aMW)
With a customer base of over 67,000, the commercial class represents the diversity of the service area economy, ranging from residential subdivision pressurized irrigation to manufacturing.
Due to this diversity, the category is further 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 7 shows the breakdown of the categories and their relative sizes based on 2014 billed energy sales.
0
100
200
300
400
500
600
700
1979 1984 1989 1994 1999 2004 2009 2014 2019 2024 2029 2034
Weather Adjusted Expected Case 70th Percentile 90th Percentile
Appendix A—Sales and Load Forecast Idaho Power Company
Page 18 2015 Integrated Resource Plan
The commercial-customer forecast for 2015 to 2034 shows an average annual growth rate of
1.7 percent.

Figure 7. Commercial building share
As indicated in Figure 7, retail goods and service providers represent the majority of customers, with 35% of the total in 2014. The number of commercial customers is expected to increase at an average annual rate of 1.7 percent, reaching 94,900 customers by December 2034. Much of the
future commercial customer growth is expected to come from retail goods and services.
Historically, this category growth is a function of the growth in residential customers.
Recent trends indicate continued growth in communications and general manufacturing and small industrial categories.
In 1984, customers in the commercial category consumed approximately 17 percent
of Idaho Power system sales, growing to 28 percent by 2014. This share is forecast to
remain at the upper end of this range throughout the planning period.
Figure 8 shows historical and forecast average use per customer (UPC) for the entire category. The commercial-use-per-customer metric in Figure 8 represents an aggregated metric for a highly diverse group of customers with significant differences in total energy use per customer,
but it is instructive in aggregate for comparative purposes.
The UPC peaked in 2001 at 67,400 kWh and has declined at approximately 0.31 percent
compounded annually to 2014. The UPC is forecast to decrease at an annual rate of 0.46 percent over the planning period. For the category as a whole, common elements that drive use down include increases in electricity prices, business-cycle recessions, and the adoption of
energy efficiency technology. Within the sub-categories, the UPC varies widely from
manufacturing/industrial at 159,500 kWh per customer to communications at 44,250 kWh
(2014 basis).
14%
5%
3%
7%
3%
5%
3%
5%
14%3%
35%
3%
Agriculture 14%
Assembly 5%
Communication 3%
Education 7%
Health Care 4%
Lodging 5%
Mfg/Food 3%
Mfg/Ind. 5%
Office 14%
Other 3%
Retail Goods/Svcs. 35%
Warehouse 3%
Idaho Power Company Appendix A—Sales and Load Forecast
2015 Integrated Resource Plan Page 19

Figure 8. Forecast commercial use per customer (weather-adjusted kWh)
Figure 9 shows the diversity in the commercial segments’ UPC as well as the trend for these
sectors. The figure shows the 2014 UPC for each segment relative to the 2010 UPC. A value of 1.0 indicates the UPC has not changed over this period. The figure supports the general decline of the aggregated trend of Figure 7 but highlights differences in energy and economic dynamics
within the commercial category not evident in the residential category.

Figure 9. Commercial categories UPC, 2014 relative to 2010
Energy efficiency implementation is a large determinant in UPC decline, particularly in
high-growth categories, such as retail goods and services, communication, and office, where many structures are new and subject to efficient building code requirements. Increases in
the UPC, such as in the water/agriculture (Water/Ag.) category are indicative of an increasing
density of pumps and water treatment consolidation. Other influences include a difference in
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
1979 1984 1989 1994 1999 2004 2009 2014 2019 2024 2029 2034
Actual Forecast
Hi
0
0.2
0.4
0.6
0.8
1
1.2
1.4
Appendix A—Sales and Load Forecast Idaho Power Company
Page 20 2015 Integrated Resource Plan
price sensitivity, sensitivity to business cycles and weather changes, and degree and trends
in automation. In addition, aggregate commercial UPC can vary when a customer’s use
increases to the point where it must, by tariff rules, migrate to an industrial (Rate 19) category.
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 conservation adoption.
Idaho Power Company Appendix A—Sales and Load Forecast
2015 Integrated Resource Plan Page 21
IRRIGATION
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 from 213 aMW in 2015 to
235 aMW in 2034, an average annual compound growth rate of 0.5 percent. The expected-case,
70th-percentile, and 90th-percentile scenarios forecast slow growth in irrigation load from 2015
to 2034. In the 70th-percentile scenario, irrigation load is projected to be 226 aMW in 2015 and 248 aMW in 2034. The individual irrigation load forecasts (Table 7 and Figure 10) illustrate the
poorer economic conditions and dramatic reduction in land put into production in the mid-1980s.
Table 7. Irrigation load growth (aMW)
Growth 2015 2019 2024 2034 Annual Growth Rate 2015–2034
90 Percentile ................................................................244 250 254 266 0.5%
70 Percentile ................................................................226 232 235 248 0.5%
Expected Case ................................................................213 218 222 235 0.5%

Figure 10. Forecast irrigation load (aMW)
The annual average loads in Table 7 and Figure 10 are calculated using the 8,760 hours in a
typical year. In the highly seasonal irrigation sector, over 97 percent of the annual energy is
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
0
50
100
150
200
250
300
350
400
1979 1984 1989 1994 1999 2004 2009 2014 2019 2024 2029 2034
Weather Adjusted Expected Case 70th Percentile 90th Percentile
Hi
Appendix A—Sales and Load Forecast Idaho Power Company
Page 22 2015 Integrated Resource Plan
consumed during July for general business sales. The monthly forecast load figures are being
evaluated for resource planning purposes, not the annual average loads.
The 2015 irrigation sales forecast is higher than the 2013 IRP forecast throughout the 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 taken advantage of higher market prices
over the past few years and have put high-lift acreage back into production. Additionally,
the conversion of flood/furrow irrigation to sprinkler irrigation, primarily related to farmers
trying to reduce labor costs, explains most of the increased energy consumption in recent years.
The 2015 irrigation sales forecast model considers several factors affecting electricity sales to the irrigation class, including temperature; precipitation; spring rainfall; 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.
In early 2001, wholesale electricity prices reached unprecedented levels; Idaho Power, in an attempt to minimize reliance on the market, developed a voluntary load-reduction program that
paid irrigators to reduce their electricity consumption in 2001. The voluntary load-reduction
program was effective and resulted in a 30-percent, or approximately 500,000-megawatt-hour
(MWh), reduction in 2001 irrigation sales. The 2001 irrigation sales and corresponding loads
have been adjusted upward by 499,319 MWh to reflect a more normal 2001 irrigation season.
Actual irrigation electricity sales have grown from the 1970 level of 816,000 MWh to a peak
amount of 2,097,000 MWh in 2013. Idaho Power projects no growth in irrigated acres in the
service area and limited growth in sprinkler irrigation or conversion to sprinkler irrigation.
In 1977, irrigation sales reached a maximum proportion of 20 percent of Idaho Power system
sales. In 1984, they represented nearly 16 percent of weather-normalized Idaho Power system sales. In 2014, the irrigation proportion of system sales was 14 percent due to the much higher
relative growth in other customer classes. By 2034, irrigation customers are projected to
consume about 11 percent of Idaho Power system sales. Figure 17 shows the irrigation
customer load proportion.
In 1980, Idaho Power had about 10,850 active irrigation accounts. By 2014, the number of active irrigation accounts had increased to 19,328 and is projected to be nearly 25,000 at the end of the
planning period in 2034.
Since 1988, Idaho Power has experienced growth in the number of irrigation customers but
very 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. However, the conversion rate is low, 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 the future, 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.
Idaho Power Company Appendix A—Sales and Load Forecast
2015 Integrated Resource Plan Page 23
INDUSTRIAL
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 1975, Idaho Power had about 70 industrial customers, which represented about 10 percent of
Idaho Power’s system sales. By December 2014, the number of industrial customers had risen
to 118, representing approximately 17 percent of system sales. Given the wide range of customer’s energy use in the tariff schedule, customer counts are primarily illustrative of the positive economic conditions in the service area. Customers with load greater than Schedule 19
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 277 aMW in 2015 to 401 aMW in 2034, an average annual growth rate of 2.0 percent (Table 8). To a large degree, industrial load variability is not due to weather conditions as is residential, commercial, and irrigation;
therefore, the forecasts in the 70th- and 90th-percentile weather-scenarios are identical to the
expected-case industrial-load scenario. The industrial load forecast is pictured in Figure 11.
Table 8. Industrial load growth (aMW)
Growth 2015 2019 2024 2034 Annual Growth Rate 2015–2034
Expected Case ................................................................277 313 341 401 2.0%

Figure 11. Forecast industrial load (aMW)
0
50
100
150
200
250
300
350
400
450
1979 1984 1989 1994 1999 2004 2009 2014 2019 2024 2029 2034
Actual Expected Case
Appendix A—Sales and Load Forecast Idaho Power Company
Page 24 2015 Integrated Resource Plan
The industrial category reflects a wide range of business activity ranging from manufacturing to
health care. To better specify forecast regression models, the customers are segmented into
economic and energy-use profile categories. The industrial energy forecast models integrated the
July 2014 national, state, MSA, and county economic time-series from Moody’s Analytics and associated derived economic time-series for Idaho Power’s service area.
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
coefficients from the industry group regression models that are applied to the appropriate forecasts of independent time series of energy use.
Figure 12 illustrates the 2014 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 (38%),
followed by dairy (18%) and electronics/technology (Electech) (7%). The categorization scheme
includes a range of industrial building types (assembly, lodging, mercantile, warehouse, office, education, health care). These categorizations provide the basis for capturing, modeling,
and forecasting the shifting economic landscape that influences industrial category
electricity sales.

Figure 12. Industrial electricity consumption by industry group (based on 2014 sales)
10%
12%
13%
31%
0%
0%
1%
9%
11%
2%
2%0%
6%3%
Industrial Mfg 10%
Construction 12%
Electech 13%
Dairy 31%
Food Mfg 0%
Water Related 0%
Assembly 1%
Education 9%
Health Care 11%
Lodging 2%
Mercantile 2%
Office—Large 0%
Other 6%
Warehouse 3%
Idaho Power Company Appendix A—Sales and Load Forecast
2015 Integrated Resource Plan Page 25
ADDITIONAL FIRM LOAD
The additional firm load category consists of Idaho Power’s largest customers. Idaho Power’s
tariff requires the company serve requests for electric service greater 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 commission. A special contract
allows customer-specific, cost-of-service analysis and unique operating characteristics to be
accounted for in the agreement.
A special contract also allows Idaho Power to provide requested service consistent with system capability and reliability. Idaho Power currently has three special-contract customers recognized as firm-load customers. These special-contract customers are Micron Technology,
Simplot Fertilizer, and the INL.
In the expected-case forecast, additional firm load is expected to increase from 101 aMW
in 2015 to 113 aMW in 2034, an average growth rate of 0.6 percent per year over the planning period (Table 9). The additional firm load energy and demand forecasts in the 70th and 90th-percentile scenarios are identical to the expected-load growth scenario. The scenario
of projected additional firm load is illustrated in Figure 13.
Table 9. Additional firm load growth (aMW)
Growth 2015 2019 2024 2034 Annual Growth Rate 2015–2034
Expected Case ................................................................101 104 115 113 0.6%

Figure 13. Forecast additional firm load (aMW)
0
25
50
75
100
125
150
175
200
1979 1984 1989 1994 1999 2004 2009 2014 2019 2024 2029 2034
Actual Expected Case
Appendix A—Sales and Load Forecast Idaho Power Company
Page 26 2015 Integrated Resource Plan
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
expected to increase based on the market demand for their products.
Simplot Fertilizer
The Simplot Fertilizer plant is the largest producer of phosphate fertilizer in the western 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.
Idaho National Laboratory
The DOE provided an energy-consumption and peak-demand forecast through 2034 for the INL. The forecast calls for loads to slowly rise through 2021, rise dramatically through 2024,
and stay near that higher level throughout the remainder of the forecast period.

Idaho Power Company Appendix A—Sales and Load Forecast
2015 Integrated Resource Plan Page 27
COMPANY SYSTEM PEAK
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, July 2,
2013, at 4:00 p.m. The previous summer peak demand was 3,245 MW and occurred on
Thursday, July 12, 2012, at 4:00 p.m. The system summer peak load growth accelerated
from 1998 to 2008 as a record number of residential, commercial, and industrial customers were added to the system and A/C became standard in nearly all new residential homes and new commercial buildings.
In the 90th-percentile forecast, the system summer peak load is expected to increase from
3,537 MW in 2015 to 4,719 MW in 2034, an average growth rate of 1.5 percent per year over
the planning period (Table 10). In the 95th-percentile forecast, the system summer peak load is
expected to increase from 3,576 MW in 2015 to 4,773 MW in 2034. The three scenarios of projected system summer peak loads are illustrated in Figure 14. Much of the variation in peak
load is due to weather conditions. Notably, the 2001 summer peak was dampened by the nearly
30-percent curtailment in irrigation load due to the 2001 voluntary load-reduction program.
Table 10. System summer peak load growth (MW)
Growth 2015 2019 2024 2034 Annual Growth Rate 2015–2034
95 Percentile ................................................................3,576 3,847 4,151 4,773 1.5%
90 Percentile ................................................................3,537 3,805 4,105 4,719 1.5%
50 Percentile ................................................................3,313 3,562 3,839 4,407 1.5%

Figure 14. Forecast system summer peak (MW)
1,000
1,400
1,800
2,200
2,600
3,000
3,400
3,800
4,200
4,600
5,000
1979 1984 1989 1994 1999 2004 2009 2014 2019 2024 2029 2034
Actual less Astaris Actual 50th Percentile 90th Percentile 95th Percentile
Appendix A—Sales and Load Forecast Idaho Power Company
Page 28 2015 Integrated Resource Plan
The all-time system winter peak demand was 2,528 MW, reached on Thursday, December 10,
2009, at 8:00 a.m. As shown in Figure 15, 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.
In the 90th-percentile forecast, the system winter peak load is expected to increase from
2,603 MW in 2015 to 3,077 MW in 2034, an average growth rate of 0.9 percent per year over
the planning period (Table 11). In the 95th-percentile forecast, the system winter peak load is expected to increase from 2,625 MW in 2015 to 3,100 MW in 2034, an average growth rate of
0.9 percent per year over the planning period (Table 11). The three scenarios of projected
system winter peak load are illustrated in Figure 13.
Table 11. System winter peak load growth (MW)
Growth 2015 2019 2024 2034 Annual Growth Rate 2015–2034
95 Percentile ................................................................2,625 2,723 2,853 3,100 0.9%
90 Percentile ................................................................2,603 2,701 2,830 3,077 0.9%
50 Percentile ................................................................2,330 2,428 2,557 2,805 1.0%

Figure 15. Forecast system winter peak (MW)

Idaho Power Company Appendix A—Sales and Load Forecast
2015 Integrated Resource Plan Page 29
COMPANY SYSTEM LOAD
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 of the 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 1.2 percent per year from 2015 to 2034. Company system load projections are reported in Table 12 and shown in Figure 16.
In the expected-case forecast, the company system load is expected to increase from 1,786 aMW
in 2015 to 2,240 aMW in 2034. In the 70th-percentile forecast, the company system load is
expected to increase from 1,829 aMW in 2015 to 2,292 aMW by 2034, an average growth rate of 1.2 percent per year over the planning period (Table 12).
Table 12. System load growth (aMW)
Growth 2015 2019 2024 2034 Annual Growth Rate 2015–2034
90 Percentile ................................................................1,900 2,021 2,139 2,378 1.2%
70 Percentile ................................................................1,829 1,946 2,059 2,292 1.2%
Expected Case ................................................................1,786 1,900 2,012 2,240 1.2%
Figure 16. Forecast system load (aMW)
700
1,000
1,300
1,600
1,900
2,200
2,500
2,800
1979 1984 1989 1994 1999 2004 2009 2014 2019 2024 2029 2034
WA less Astaris Weather Adjusted Expected Case 70th Percentile 90th Percentile
Appendix A—Sales and Load Forecast Idaho Power Company
Page 30 2015 Integrated Resource Plan
The Astaris 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. The system load, excluding Astaris, portrays 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 17.
Residential sales are forecast to be nearly 28 percent higher in 2034, gaining 1.5 million MWh over 2015. Commercial sales are also expected to be 20 percent higher, or 0.8 million MWh,
than in 2015, followed by industrial (45 percent higher or 1.1 million additional MWh)
and irrigation (10 percent higher in 2034 than 2015). Electricity sales to Astaris ended
in April 2002.

Figure 17. Composition of system company electricity sales (thousands of MWh)
The additional firm-load category (which represents sales to Micron Technology,
Simplot Fertilizer, and the INL) is forecast to grow by 24 percent from 2015 to 2034.
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
20,000
1984 1989 1994 1999 2004 2009 2014 2019 2024 2029 2034
Residential Commercial Industrial Irrigation Additional Firm Sales Astaris
Idaho Power Company Appendix A—Sales and Load Forecast
2015 Integrated Resource Plan Page 31
CONTRACT OFF-SYSTEM LOAD
The contract off-system 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 into additional long-term contracts to supply firm energy to off-system customers if surplus energy is available.
Appendix A—Sales and Load Forecast Idaho Power Company
Page 32 2015 Integrated Resource Plan
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Idaho Power Company Appendix A—Sales and Load Forecast
2015 Integrated Resource Plan Page 33
ENERGY EFFICIENCY AND DEMAND 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 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. Specifically, the models capture the physical flow of energy-efficient products through shipment
data to resellers and installers. The source for this data is the DOE (the data also serves as input
to the DOE 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.
Efficiency data for irrigation customers and some commercial and industrial customers
(i.e., manufacturing related) is not directly surveyed and collected by the DOE; therefore,
models for efficiency impacts have been developed using a methodology established in Itron’s
white paper, Incorporating DSM into the Load Forecast.1 This approach develops statistical methods to recognize efficiency trends from historical energy efficiency utility acquisition,
recognizing that historical trends are embedded in the actual sales data (which serve as the basis
for the sector’s forecast). Trends associated with future acquisitions from these existing
programs (and their cumulative impacts) are similarly developed to compare with historical
trends. 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.
Regardless of the method, efficiency impacts from the models are compared to the DOE’s
population of utility acquisitions to ensure the models are correctly 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

1 Stuart McMenamin and Mark Quan. Incorporating DSM into the Load Forecast. Itron,
https://www.itron.com/na/PublishedContent/Incorporating%20DSM%20into%20the%20Load%20Forecast.pdf (accessed February 3, 2011).
Appendix A—Sales and Load Forecast Idaho Power Company
Page 34 2015 Integrated Resource Plan
the amount of energy lost in transmitting the electricity from the generation source to the
customer’s meter.
The influence of new efficiency programs is not typically prepared in time to be available for
input into the forecast models. Therefore, the impacts of these new programs are accounted for in the IRP load and resource balance prior to determining the need for additional supply-side
resources. The forecast performance of existing and new energy efficiency and demand response
programs is shown in the load and resource balance in Appendix C—Technical Appendix.
Demand Response
Beginning with the 2009 IRP, demand response programs have been effectively treated as
supply-side resources and accounted for in the load and resource balance. Demand response
program data, including operational targets for demand reduction, program expenses, and cost-
effective summaries, are detailed in Appendix 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 efficiency 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 programs, as energy
efficiency programs are considered in the sales and load forecast while all demand response
programs are included in the load and resource balance.
A thorough description of each of the energy efficiency and demand response programs is
included in Appendix B—Demand Side Management 2014 Annual Report.
Idaho Power Company Appendix A1. Historical and Projected Sales and Load
2015 Integrated Resource Plan Page 35
Appendix A1. Historical and Projected Sales and Load
Residential Load
Historical Residential Sales and Load, 1974–2014 (weather adjusted)
Year Average Customers Percent Change kWh per Customer Billed Sales (thousands of MWh) Percent Change Average Load (aMW)
1974 160,151 – 12,067 1,932 – 223
1977 184,561 5.0% 13,698 2,528 289
1980 209,629 3.3% 14,575 3,055 348
1983 219,849 1.5% 14,364 3,158 361
1986 227,081 0.8% 14,328 3,254 369
1989 233,370 1.1% 14,374 3,354 382
1992 249,767 2.7% 14,149 3,534 -404
1994 267,854 3.7% 14,010 3,753 430
1997 294,674 3.0% 13,670 4,028 461
2000 322,402 3.0% 13,412 4,324 494
2003 349,219 2.8% 12,666 4,423 507
2006 387,707 3.8% 12,910 5,005 573
2009 405,144 0.7% 12,716 5,152 -587

Appendix A1. Historical and Projected Sales and Load Idaho Power Company
Page 36 2015 Integrated Resource Plan
Residential Load
Projected Residential Sales and Load, 2015–2034
Year Average Customers Percent Change kWh per Customer Billed Sales (thousands of MWh) Percent Change Average Load (aMW)
2015 432,909 1.9% 11,884 5,145 588
2016 442,519 2.2% 11,910 5,271 603
2017 452,660 2.3% 11,868 5,372 614
2018 462,757 2.2% 11,759 5,442 622
2019 472,216 2.0% 11,665 5,509 629
2020 480,984 1.9% 11,553 5,557 635
2021 489,217 1.7% 11,481 5,617 642
2022 497,232 1.6% 11,410 5,673 648
2023 505,314 1.6% 11,361 5,741 656
2024 513,361 1.6% 11,345 5,824 666
2025 521,365 1.6% 11,333 5,908 1.5%675
2026 529,313 1.5% 11,324 5,994 685
2027 537,191 1.5% 11,316 6,079 695
2028 544,909 1.4% 11,317 6,167 705
2029 552,467 1.4% 11,320 6,254 715
2030 559,841 1.3% 11,304 6,328 723
2031 566,967 1.3% 11,282 6,396 731
2032 573,885 1.2% 11,265 6,465 739
2033 580,611 1.2% 11,256 6,535 747
2034 587,224 1.1% 11,248 6,605 755

Idaho Power Company Appendix A1. Historical and Projected Sales and Load
2015 Integrated Resource Plan Page 37
Commercial Load
Historical Commercial Sales and Load, 1974–2014 (weather adjusted)
Year Average Customers Percent Change kWh per Customer Billed Sales (thousands of MWh) Percent Change Average Load (aMW)
1974 24,096 – 49,028 1,181 – 136
1978 27,831 2.7% 52,477 1,460 168
1979 28,087 0.9% 56,391 1,584 180
1980 28,797 2.5% 54,143 1,559 -178
1981 29,567 2.7% 54,285 1,605 184
1984 31,554 2.5% 53,552 1,690 193
1985 32,418 2.7% 54,128 1,755 201
1986 33,208 2.4% 54,069 1,796 204
1987 33,975 2.3% 53,411 1,815 207
1991 37,922 3.1% 56,390 2,138 244
1992 39,022 2.9% 56,424 2,202 252
1993 40,047 2.6% 58,126 2,328 266
1994 41,629 4.0% 58,283 2,426 278
1998 48,404 3.4% 62,804 3,040 348
1999 49,430 2.1% 64,238 3,175 363
2000 50,117 1.4% 66,012 3,308 379
2001 51,501 2.8% 67,409 3,472 4.9% 396
2004 55,577 2.6% 64,013 3,558 406
2005 57,145 2.8% 63,552 3,632 415
2006 59,050 3.3% 63,513 3,750 429
2007 61,640 4.4% 63,412 3,909 447
2011 64,921 0.8% 58,455 3,795 433
2012 65,599 1.0% 58,980 3,869 440
2013 66,357 1.2% 58,588 3,888 445
2014 67,113 1.1% 59,036 3,962 452

Appendix A1. Historical and Projected Sales and Load Idaho Power Company
Page 38 2015 Integrated Resource Plan
Commercial Load
Projected Commercial Sales and Load, 2015–2034
Year Average Customers Percent Change kWh per Customer Billed Sales (thousands of MWh) Percent Change Average Load (aMW)
2015 68,174 1.6% 59,790 4,076 2.9% 466
2016 69,407 1.8% 59,719 4,145 1.7% 473
2017 70,839 2.1% 59,044 4,183 0.9% 478
2018 72,366 2.2% 58,207 4,212 0.7% 481
2019 73,896 2.1% 57,478 4,247 0.8% 485
2020 75,384 2.0% 56,853 4,286 0.9% 490
2021 76,816 1.9% 56,332 4,327 1.0% 494
2022 78,209 1.8% 55,865 4,369 1.0% 499
2023 79,591 1.8% 55,409 4,410 0.9% 504
2024 80,976 1.7% 54,980 4,452 1.0% 509
2025 82,364 1.7% 54,581 4,496 1.0% 513
2026 83,749 1.7% 54,189 4,538 1.0% 518
2027 85,129 1.6% 53,793 4,579 0.9% 523
2028 86,500 1.6% 53,447 4,623 1.0% 528
2029 87,856 1.6% 53,150 4,670 1.0% 533
2030 89,196 1.5% 52,844 4,714 0.9% 538
2031 90,513 1.5% 52,544 4,756 0.9% 543
2032 91,806 1.4% 52,293 4,801 0.9% 548
2033 93,078 1.4% 52,098 4,849 1.0% 554
2034 94,332 1.3% 51,910 4,897 1.0% 559

Idaho Power Company Appendix A1. Historical and Projected Sales and Load
2015 Integrated Resource Plan Page 39
Irrigation Load
Historical Irrigation Sales and Load, 1974–2014 (weather adjusted)
Year
Maximum Active
Customers
Percent
Change
kWh per
Customer
Billed Sales
(thousands of MWh)
Percent
Change
Average
Load (aMW)
1974 8,971 – 147,923 1,327 – 151
1975 9,480 5.7% 153,993 1,460 167
1976 9,936 4.8% 156,365 1,554 177
1980 10,854 1.3% 157,784 1,713 -195
1981 11,248 3.6% 165,251 1,859 212
1982 11,312 0.6% 153,416 1,735 -198
1983 11,133 -1.6% 143,575 1,598 -182
1986 11,308 -2.3% 133,203 1,506 -172
1987 11,254 -0.5% 130,082 1,464 -167
1988 11,378 1.1% 137,564 1,565 178
1989 11,957 5.1% 138,406 1,655 189
1990 12,340 3.2% 148,368 1,831 10.6%209
1993 13,078 2.1% 125,883 1,646 -188
1994 13,559 3.7% 131,758 1,787 204
1995 13,679 0.9% 126,751 1,734 -198
1996 14,074 2.9% 125,559 1,767 201
2000 15,253 2.3% 128,221 1,956 223
2001 15,522 1.8% 117,764 1,828 -209
2002 15,840 2.0% 111,181 1,761 -201
2003 16,020 1.1% 111,173 1,781 203
2007 17,001 -0.4% 106,506 1,811 207
2008 17,428 2.5% 110,770 1,930 220
2009 17,708 1.6% 100,877 1,786 -204
2010 17,846 0.8% 101,364 1,809 207
2013 19,017 1.8% 105,797 2,012 230
2014 19,328 1.6% 104,512 2,020 231

Appendix A1. Historical and Projected Sales and Load Idaho Power Company
Page 40 2015 Integrated Resource Plan
Irrigation Load
Projected Irrigation Sales and Load, 2015–2034
Year
Maximum Active
Customers
Percent
Change
kWh per
Customer
Billed Sales
(thousands of MWh)
Percent
Change
Average
Load (aMW)
2015 19,566 1.2% 95,218 1,863 -213
2016 19,847 1.4% 95,841 1,902 217
2017 20,127 1.4% 95,191 1,916 219
2018 20,408 1.4% 93,999 1,918 219
2019 20,688 1.4% 92,504 1,914 -218
2020 20,970 1.4% 91,789 1,925 219
2021 21,250 1.3% 91,179 1,938 221
2022 21,531 1.3% 90,194 1,942 222
2023 21,814 1.3% 89,126 1,944 222
2024 22,092 1.3% 88,442 1,954 222
2025 22,373 1.3% 87,905 1,967 225
2026 22,653 1.3% 87,365 1,979 226
2027 22,933 1.2% 86,784 1,990 227
2028 23,215 1.2% 86,171 2,000 228
2029 23,495 1.2% 85,649 2,012 230
2030 23,777 1.2% 85,060 2,022 231
2031 24,056 1.2% 84,446 2,031 232
2032 24,338 1.2% 83,751 2,038 232
2033 24,617 1.1% 83,159 2,047 234
2034 24,899 1.1% 82,533 2,055 235

Idaho Power Company Appendix A1. Historical and Projected Sales and Load
2015 Integrated Resource Plan Page 41
Industrial Load
Historical Industrial Sales and Load, 1974–2014 (not weather adjusted)
Year Average Customers Percent Change kWh per Customer Billed Sales (thousands of MWh) Percent Change Average Load (aMW)
1974 65 – 11,464,249 739 – 84
1978 99 17.6% 9,786,753 972 111
1979 109 9.6% 9,989,158 1,087 126
1980 112 2.7% 9,894,706 1,106 125
1981 118 5.7% 9,718,723 1,148 132
1984 124 1.5% 10,369,789 1,282 147
1985 125 1.2% 10,844,888 1,357 155
1986 129 2.7% 10,550,145 1,357 -155
1987 134 4.1% 11,006,455 1,474 169
1991 135 2.5% 12,699,665 1,719 196
1992 140 3.4% 12,650,945 1,770 203
1993 141 0.5% 13,179,585 1,854 212
1994 143 1.7% 13,616,608 1,948 223
1998 111 4.6% 19,378,734 2,145 244
1999 108 -2.3% 19,985,029 2,160 247
2000 107 -0.8% 20,433,299 2,191 250
2001 111 3.5% 20,618,361 2,289 260
2004 117 4.3% 19,417,310 2,269 259
2005 126 7.9% 18,645,220 2,351 270
2006 127 1.0% 18,255,385 2,325 -265
2007 123 -3.6% 19,275,551 2,366 270
2011 120 -1.1% 18,597,050 2,230 -254
2012 115 -4.2% 19,757,921 2,271 258
2013 114 -0.7% 20,281,837 2,314 265
2014 113 -0.7% 20,863,653 2,363 271

Appendix A1. Historical and Projected Sales and Load Idaho Power Company
Page 42 2015 Integrated Resource Plan
Industrial Load
Projected Industrial Sales and Load, 2015–2034
Year Average Customers Percent Change kWh per Customer Billed Sales (thousands of MWh) Percent Change Average Load (aMW)
2015 112 -1.1% 21,546,339 2,413 277
2016 113 0.9% 22,776,876 2,574 294
2017 114 0.9% 23,180,649 2,643 302
2018 115 0.9% 23,415,713 2,693 308
2019 115 0.0% 23,815,557 2,739 313
2020 115 0.0% 24,226,148 2,786 318
2021 117 1.7% 24,251,880 2,837 324
2022 117 0.0% 24,697,299 2,890 330
2023 117 0.0% 25,147,761 2,942 336
2024 118 0.9% 25,374,712 2,994 341
2025 120 1.7% 25,397,900 3,048 348
2026 121 0.8% 25,630,843 3,101 355
2027 121 0.0% 26,070,612 3,155 361
2028 121 0.0% 26,512,099 3,208 366
2029 123 1.7% 26,528,528 3,263 373
2030 124 0.8% 26,729,282 3,314 379
2031 125 0.8% 26,914,352 3,364 385
2032 125 0.0% 27,298,864 3,412 389
2033 126 0.8% 27,474,833 3,462 396
2034 127 0.8% 27,632,976 3,509 401

Idaho Power Company Appendix A1. Historical and Projected Sales and Load
2015 Integrated Resource Plan Page 43
Additional Firm Sales and Load*
Historical Additional Firm Sales and Load, 1974–2014
Year Billed Sales (thousands of MWh) Percent Change Average Load (aMW)
1974 282 – 32
1975 314 11.2% 36
1976 289 -8.1% 33
1982 368 -2.4% 42
1984 466 9.6% 53
1987 503 4.2% 57
1990 625 -6.9% 71
1993 689 1.3% 79
1996 989 12.6% 113
1999 1,122 0.8% 128
2002 1,139 1.9% 130
2004 1,157 3.3% 132
2007 1,141 -4.0% 130
2010 907 -6.0% 104
2013 867 0.5% 99
*Includes Micron Technology, Simplot Fertilizer, INL, Hoku Materials, City of Weiser, and Raft River Rural Electric Cooperative, Inc.

Appendix A1. Historical and Projected Sales and Load Idaho Power Company
Page 44 2015 Integrated Resource Plan
Additional Firm Sales and Load*
Projected Additional Firm Sales and Load, 2015–2034
Year Billed Sales (thousands of MWh) Percent Change Average Load (aMW)
2015 881 4.7% 101
2016 902 2.4% 103
2017 906 0.4% 103
2018 909 0.4% 104
2019 910 0.0% 104
2020 921 1.2% 105
2021 923 0.2% 105
2022 958 3.8% 109
2023 987 3.0% 113
2024 1,007 2.0% 115
2025 1,007 0.0% 115
2026 1,004 -0.3% 115
2027 1,004 0.0% 115
2028 999 -0.5% 114
2029 999 0.0% 114
2030 1,004 0.5% 115
2031 1,004 0.0% 115
2032 999 -0.5% 114
2033 999 0.0% 114
2034 994 -0.5% 113
*Includes Micron Technology, Simplot Fertilizer, and the INL

Idaho Power Company Appendix A1. Historical and Projected Sales and Load
2015 Integrated Resource Plan Page 45
Company System Load (excluding Astaris)
Historical Company System Sales and Load, 1974–2014 (weather adjusted)
Year Billed Sales (thousands of MWh) Percent Change Average Load (aMW)
1974 – 682
1978 4.3% 898
1979 8.7% 969
1980 -0.1% 964
1981 3.3% 1,003
1984 1.8% 1,009
1985 2.3% 1,037
1986 0.8% 1,038
1987 1.0% 1,053
1991 2.3% 1,211
1992 2.1% 1,241
1993 1.8% 1,262
1994 4.6% 1,324
1998 12,4.0% 1,510
1999 2.6% 1,549
2000 3.3% 1,601
2001 1.1% 1,616
2004 2.4% 1,654
2005 1.7% 1,688
2006 2.4% 1,726
2007 1 3.3% 1,784
2011 -0.2% 1,711
2012 1.7% 1,737
2013 0.5% 1,755
2014 1.0% 1,768

Appendix A1. Historical and Projected Sales and Load Idaho Power Company
Page 46 2015 Integrated Resource Plan
Company System Load
Projected Company System Sales and Load, 2015–2034
Year Billed Sales (thousands of MWh) Percent Change Average Load (aMW)
2015 0.9% 1,786
2016 2.9% 1,835
2017 1.5% 1,864
2018 1.0% 1,883
2019 0.9% 1,900
2020 1.0% 1,918
2021 1.1% 1,941
2022 1.2% 1,964
2023 1.2% 1,988
2024 1.3% 2,012
2025 1.2% 2,037
2026 1.2% 2,061
2027 1.1% 2,085
2028 1.1% 2,107
2029 1.2% 2,133
2030 1.1% 2,156
2031 17,552 1.0% 2,177
2032 0.9% 2,195
2033 1.0% 2,219
2034 0.9% 2,240