201307012013 IRP Appendix A.PDF

Sales and Load Forecast
2013 Integrated
Resource Plan
June 2013
APPENDIX A

June 2013
Integrated Resource Plan
ACKNOWLEDGEMENT
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 2013 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
of individuals that represent many different
departments 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.
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.
2013
Printed on recycled paper
Sales and Load Forecast
APPENDIX A

Idaho Power Company Appendix A—Sales and Load Forecast
2013 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
2013 IRP Sales and Load Forecast ..................................................................................................3
Average Load .............................................................................................................................3
Peak-Hour Demands ..................................................................................................................4
Overview of the Forecast .................................................................................................................7
Fuel Prices ..................................................................................................................................7
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 ........................................................................................................................................25
Additional Firm Load ....................................................................................................................27
Micron Technology ..................................................................................................................28
Simplot Fertilizer .....................................................................................................................28
Idaho National Laboratory .......................................................................................................28
Hoku Materials.........................................................................................................................28
“Special” Contract ...................................................................................................................28
Company System Peak ..................................................................................................................29
Company System Load ..................................................................................................................31
Contract Off-System Load .............................................................................................................33
Energy Efficiency and Demand Response .....................................................................................35
Energy Efficiency ....................................................................................................................35
Demand Response ....................................................................................................................36
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LIST OF TABLES
Table 1. Residential fuel-price escalation (2013–2032) (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) .....................................................................................25
Table 9. Additional firm load growth (aMW) ............................................................................27
Table 10. System summer peak load growth (MW) ....................................................................29
Table 11. System winter peak load growth (MW) .......................................................................30
Table 12. System load growth (aMW) .........................................................................................31

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. Forecast commercial use per customer (weather-adjusted kWh) ................................18
Figure 8. Forecast irrigation load (aMW) ...................................................................................21
Figure 9. Forecast industrial load (aMW) ...................................................................................25
Figure 10. Industrial electricity consumption by industry group (based on 2012 figures) ...........26
Figure 11. Forecast additional firm load (aMW) ..........................................................................27
Figure 12. Forecast system summer peak (MW) ..........................................................................29
Figure 13. Forecast system winter peak (MW) .............................................................................30
Figure 14. Forecast system load (aMW) .......................................................................................31
Figure 15. Composition of system company electricity sales (thousands of MWh) .....................32

Idaho Power Company Appendix A—Sales and Load Forecast
2013 Integrated Resource Plan Page iii
LIST OF APPENDICES
Appendix A1. Historical and Projected Sales and Load .............................................................37
Residential Load ......................................................................................................................37
Historical Residential Sales and Load, 1972–2012 (weather adjusted) .............................37
Projected Residential Sales and Load, 2013–2032 ............................................................38
Commercial Load.....................................................................................................................39
Historical Commercial Sales and Load, 1972–2012 (weather adjusted) ...........................39
Projected Commercial Sales and Load, 2013–2032 ..........................................................40
Irrigation Load .........................................................................................................................41
Historical Irrigation Sales and Load, 1972–2012 (weather adjusted) ................................41
Projected Irrigation Sales and Load, 2013–2032 ...............................................................42
Industrial Load .........................................................................................................................43
Historical Industrial Sales and Load, 1972–2012 (weather adjusted) ...............................43
Projected Industrial Sales and Load, 2013–2032 ...............................................................44
Additional Firm Sales and Load* ............................................................................................45
Historical Additional Firm Sales and Load, 1972–2012 ...................................................45
Projected Additional Firm Sales and Load, 2013–2032 ....................................................46
Company System Load (excluding Astaris) ............................................................................47
Historical Company System Sales and Load, 1972–2012 (weather adjusted) ..................47
Company System Load (including Astaris) .............................................................................48
Historical Company System Sales and Load, (1972–2012) (weather adjusted) ...............48
Astaris Sales and Load (1972–2002) (weather adjusted) ..................................................48
Projected Company System Sales and Load, 2013–2032 ..................................................49
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Idaho Power Company Appendix A—Sales and Load Forecast
2013 Integrated Resource Plan Page 1
INTRODUCTION
Idaho Power has prepared Appendix A—Sales and Load Forecast as an appendix to its 2013 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 2013 through 2032.
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. However, the actual path of future electricity sales will not follow the exact path suggested by the expected-case load forecast. Therefore, 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-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.
The expected-case load forecast assumes median temperatures and median rainfall. Because actual loads can vary significantly depending on weather conditions, two alternative
scenarios were considered: a 70th-percentile average load forecast and 90th-percentile average
load forecast. 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).
In the expected-case scenario, Idaho Power’s system load is forecast to increase to
2,154 average megawatts (aMW) in the year 2032 from the 2013 forecast load of 1,759 aMW.
The expected-case forecast system load growth rate averages 1.1 percent per year over the
20-year planning period (2013–2032). In the more critical 70th-percentile load forecast used for resource planning, the system load is forecast to reach 2,201 aMW by 2032. The Idaho Power system peak load (95th percentile) is forecast to grow to 4,418 megawatts (MW) in the year 2032
from the actual system summer peak of 3,245 MW that occurred on Thursday, July 12, 2012,
at 4:00 p.m. In the expected-case scenario, the Idaho Power system peak increases at an average
growth rate of 1.4 percent per year over the 20-year planning period (2013–2032). The number of Idaho Power active retail customers is expected to increase from the December 2012 level of 500,000 customers to over 667,000 customers at year-end 2032.
This year’s economic forecast was based on a forecast of national and regional economic
activity developed by Moody’s Analytics, Inc., a national econometric consulting firm.
Moody’s Analytics June 2012 macroeconomic forecast strongly influenced Appendix A—Sales and Load Forecast. 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
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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.
Economic growth assumptions influence several classes of service growth rates. The number of
households in Idaho is projected to grow at an annual average rate of 1.2 percent during the forecast period. The growth in the number of households within individual counties in
Idaho Power’s service area differs from statewide household growth patterns. Service area
households are derived from county-specific household forecasts. The number of households,
incomes, employment projections, 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 specific assumptions were incorporated into the forecasts of the individual sectors.
Further discussion of the assumptions is presented in the sections of this report pertaining to the
individual sectors.
The future load impacts of implemented and committed Idaho Power energy efficiency demand-side management (DSM) programs are considered within Appendix A—Sales and
Load Forecast. These programs and their expected impacts are addressed in more detail in
Idaho Power’s Demand-Side Management 2012 Annual Report. This report is Appendix B to
the 2013 IRP.
During the 20-year forecast horizon, there could be major changes in the electric utility industry, such as carbon regulations and subsequent higher electricity prices impacting future electricity
demand. 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 previously described.
The impact of carbon legislation on the load forecast is reflected in retail electricity prices, which are a driver in the major sector sales forecasting model. The alternative sales and load
scenarios of Appendix A—Sales and Load Forecast were prepared under the assumption that
Idaho Power will continue to serve all customers in its franchised service area during the
planning period.
Data describing the historical and projected figures for the sales and load forecast is presented in Appendix A1 of this report.

Idaho Power Company Appendix A—Sales and Load Forecast
2013 Integrated Resource Plan Page 3
2013 IRP SALES AND LOAD FORECAST
Average Load
The 2013 IRP average system load forecast is lower than the 2011 IRP average system load
forecast in all years of the forecast period. The expected recovery reflected in the economic
forecast used for the 2011 IRP was determined too optimistic in terms of a rapid recovery from
the recession. The updated variables driving the 2013 forecast reflect this recent performance.
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 series to date. Longer-term, higher-retail electricity price
assumptions that incorporate estimates of assumed carbon legislation serve to decrease 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 2013 IRP load forecast include the following:
• The sales and load forecast prepared for the 2011 IRP reflected the expected increase in
demand for energy and peak capacity of Idaho Power’s most recent special-contract
customer, Hoku Materials, located in Pocatello, Idaho. However, since the 2011 IRP, Hoku Materials was unable to complete the construction of its manufacturing facility and
execute on its contract to take service under the special-contract tariff. For the 2013 IRP,
Idaho Power has assumed Hoku Materials will not come on-line, and the 74 aMW of
energy originally anticipated are excluded from this sales and load forecast.
• The 2011 IRP sales and load forecast included a high-probability new customer referred to as “Special”. At the time the forecast was prepared (August 2010), several interested
parties had taken significant steps toward the development and location of their
businesses within Idaho Power’s service area. At that time, it was determined that the
likelihood of the load materializing was sufficient to warrant its inclusion in the IRP. Ultimately, the contract was not completed and the load did not materialize as expected.
For the 2013 IRP, Idaho Power has assumed this “Special” contract will not come
on-line, and the 54 aMW of energy originally anticipated are excluded from this sales
and load forecast.
• The load forecast used for the 2013 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 in 2008 and 2009 dramatically slowed
the growth of new households and, consequently, the number of residential customers
being added to Idaho Power’s service area. However, in 2011 and 2012, residential and commercial customer growth, along with housing and industrial activity, have shown signs of a meaningful and sustainable recovery. By 2015, customer additions are forecast
to approach the growth that occurred prior to the housing bubble (2000–2004).
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• The electricity price forecast used to prepare the sales and load forecast in the 2013 IRP
reflects the additional plant investment and variable costs of integrating the resources
identified in the 2011 IRP preferred portfolio, including the expected costs of carbon emissions. When compared to the electricity price forecast used to prepare the 2011 IRP sales and load forecast, the 2013 IRP price forecast yields higher future prices. The retail
prices are mostly higher in the second 10 years of the planning period and impact the
sales forecast negatively, 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. The current sales and load forecast reflects only those commercial or industrial customers that have made a sufficient and significant investment indicating a commitment of the
highest probability of locating in the service area. Therefore, the large numbers of
businesses that have contacted Idaho Power and shown interest but have not made
sufficient commitments are not included in the current sales and load forecast.
• 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. 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 2013 irrigation sales forecast is slightly higher than the 2011 IRP forecast through
2015, likely due to recent high commodity prices and changing crop patterns.
Farmers have taken advantage of the commodities market by planting greater acreage than in the recent past. After 2015, the sales forecast is slightly lower than the previous
IRP forecast, primarily due to higher electricity prices. The continued conversion of
irrigation systems from labor-intensive hand-lines to electrically operated pivot sprinklers
continues to impact increased irrigation energy consumption.
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 sales and load forecast prepared for the 2011 IRP reflected the expected increase in
demand for energy and peak capacity of Idaho Power’s most recent special-contract
customer, Hoku Materials, located in Pocatello, Idaho. However, since the 2011 IRP,
Hoku Materials was unable to complete the construction of its manufacturing facility and execute on its contract to take service under the special-contract tariff. For the 2013 IRP, Idaho Power has assumed Hoku Materials will not come on-line, and the 82 MW of peak
demand originally anticipated are excluded from this sales and load forecast.
Idaho Power Company Appendix A—Sales and Load Forecast
2013 Integrated Resource Plan Page 5
• As referenced previously, the 2011 IRP sales and load forecast included a new customer
referred to as “Special” that failed to materialize. For the 2013 IRP, Idaho Power has
assumed this “Special” contract will not come on-line, and the 60 MW of peak demand originally anticipated is excluded from this sales and load forecast.
• The 2013 IRP peak-demand forecast considers the impact of committed and implemented
energy efficiency DSM programs on peak demand.
• The 2013 IRP peak-demand forecast model explicitly excludes the impact of demand response programs to establish peak impacts to effectively plan for demand response and
supply-side resources in meeting peak demand. Demand response programs impacts are
accounted for in the IRP load and resource balance 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.
• Historical peak-demand data is considered in the peak-model regressions. Based on a
historical comparison of percentiles, the July 2002, July 2003, June 2005, and July 2005
peak-day temperatures were near the 100th percentile, and their addition to the regression models impacted forecast results. More recently, all-time system peaks were reached in
July 2007, June 2008, and July 2012 and were incorporated into the peak forecast
model regressions.
• Idaho Power continues to use a median peak-day temperature driver in lieu of an average peak-day temperature driver. 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 1982 to 2011 time period (the most recent
30 years).
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Idaho Power Company Appendix A—Sales and Load Forecast
2013 Integrated Resource Plan Page 7
OVERVIEW OF THE FORECAST
The sales and load forecast is constructed by developing a separate forecast for each sales
category. Independent sales forecasts are prepared 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); the Idaho National Laboratory (INL);
and Hoku Materials. These four special-contract customers are combined into a single forecast
category labeled additional firm load. Last, the contract off-system category represents long-term contracts to supply firm energy and demand to off-system customers. At this time, there are no long-term contracts. 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 allocated to the calendar months in which they are
generated. The calendar-month sales are then converted to calendar-month load by adding losses
and dividing by the number of hours in each month.
Loss factors are determined by Idaho Power’s Distribution Planning department. The annual average energy loss coefficients are multiplied by the calendar-month load, yielding the system load, including losses.
The peak-load forecast was prepared in conjunction with the 2013 sales forecast. Idaho Power
has two distinct peak periods: 1) a winter peak, resulting 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 air conditioning (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 and contractual considerations.
The primary external factors in the forecast are macroeconomic and demographic data.
Moody’s Analytics provides the macroeconomic forecasts. The national, state, MSA, and county
economic and demographic projections are tailored to Idaho Power’s service area using an economic database developed by an outside consultant. Specific demographic projections are also developed for the service area from national and local census data.
Fuel Prices
Fuel prices, in combination with service-area economic drivers, impact long-term trends in
electricity sales. Changes in relative fuel prices can also have significant impacts on the future
Appendix A—Sales and Load Forecast Idaho Power Company
Page 8 2013 Integrated Resource Plan
demand for electricity. The sales and load forecast is also influenced by the estimated impact of
proposed carbon legislation on retail electricity prices. The carbon-impacted retail electricity
prices move higher throughout the forecast period, reducing future electricity sales. Class level
and economic-sector-level regression models were used to identify the relationships between real historical electricity prices and 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 (2013–2032) (average annual percent change)
Nominal Real*
Electricity—2013 IRP .................................................................................................................. 3.2% 1.3%
Electricity—2011 IRP .................................................................................................................. 1.5% (0.1%)
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 1972 to 2012 and over the forecast period 2013 to 2032. Both nominal and
real prices are shown. In the 2013 IRP, nominal electricity prices are expected to climb to nearly
17 cents per kilowatt-hour (kWh) by the end of the forecast period in 2032. Real electricity prices (inflation adjusted) are expected to increase over the forecast period at an average rate of 1.3 percent annually. In the 2011 IRP, nominal electricity prices were assumed to slowly climb
to nearly 13 cents per kWh by 2032, and real electricity prices (inflation adjusted) were expected
to remain flat over the forecast period at an average rate of -0.1 percent annually. The impact of
the higher real electricity price forecast on the 2013 IRP load forecast serves to slow 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 2013 IRP reflected
the additional plant investment and variable costs of integrating the resources identified in the
2011 IRP preferred portfolio, including the expected costs of carbon emissions. When compared
to the electricity price forecast used to prepare the 2011 IRP sales and load forecast, the 2013 IRP price forecast yielded higher future prices. The retail prices are mostly higher in the second 10 years of the planning period and impact the sales forecast negatively, a consequence of the
inverse relationship between electricity prices and electricity demand.
Idaho Power Company Appendix A—Sales and Load Forecast
2013 Integrated Resource Plan Page 9

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 1970 to 2011 and forecast prices from 2012 to
2032. 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. The collapse in natural gas prices that
began in 2009 led to much lower prices in 2010 and 2011. Nominal natural gas prices are
expected to rise slowly through 2014, then more rapidly throughout the remainder of the forecast
period until nearly doubling 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
1977 1982 1987 1992 1997 2002 2007 2012 2017 2022 2027 2032
Nominal Real Nominal—2011 IRP
Nominal—2013 IRP Real—2011 IRP Real—2013 IRP
Hi
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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 2013 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 on the system load. The 2011 IRP forecast model relied heavily on the forecast methodologies of the
Electric Power Research Institute (EPRI) and Oak Ridge National Laboratory. At the time,
these models did not have actual consumer adoption data or most recent domestic fuel supply
impacts of advanced technologies in crude oil production. The 2013 IRP electric-vehicle forecast
update integrates service area vehicle registration data with updated technological and economic variables impacting adoption, as well as vehicle charging behavior. This update also integrates
the fuel and technology forecasts of the Department of Energy’s (DOE) National Energy
Model (NEM).
The Idaho Power vehicle share forecast is based on a Bass diffusion model of adoption as
informed by actual vehicle registration. Load impacts from adoption are derived from assumptions of battery-only and hybrid plug-in shares evident from historical registration data and informed by NEM forecasts. The combined vehicle forecast represents just over 4 percent of
new vehicle sales in the service area at the end of the planning period. Battery-only vehicles
represent 15 percent of the total, and the updated forecast model reflects a much slower adoption
rate than anticipated in the 2011 forecast. The all-electric share is consistent with the DOE Annual Energy Outlook (AEO) 2013 update that forecasts all-electric vehicles at less than 1 percent of sales in 2040.
$0.00
$0.20
$0.40
$0.60
$0.80
$1.00
$1.20
$1.40
$1.60
$1.80
1977 1982 1987 1992 1997 2002 2007 2012 2017 2022 2027 2032
Nominal Actual Nominal Forecast Real Actual Real Forecast
Idaho Power Company Appendix A—Sales and Load Forecast
2013 Integrated Resource Plan Page 11
The resulting impact on the load forecast is about 1 aMW in 2020, reaching approximately
4 aMW at the end of the forecast period in 2032. The load impacts were allocated to the
residential and commercial sales forecasts using an 80/20 split, respectively.
Idaho Power continues to capture consumer behavioral data and other salient market information associated with electric-vehicle adoption to improve the forecasting model in future 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 1982 to
2011 (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 1,291 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.
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
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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 2013 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. The expected-case load forecast reflects the integration of existing energy
efficiency DSM program effects as a reduction to the average load forecast. In addition,
retail electricity prices also impact the growth in electricity sales long term.
Two additional load forecasts for the Idaho Power service area were prepared. The forecasts
provide a range of possible load growths for the 2013 to 2032 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 (1987–2011).
Idaho Power Company Appendix A—Sales and Load Forecast
2013 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
(1987–2011). The high- and low-case load forecasts also reflect the integration of existing
energy efficiency DSM program effects as a reduction to the average load wintertime forecasts.
Two types of probability estimates are reported in Table 3. The first probability, the probability
of exceeding, shows the likelihood that 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 that 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
that the actual growth will be closer to the growth rate specified in that scenario than to the
growth rate specified in any other scenario. For example, there is a 26-percent probability the actual growth rate will be closer to the high scenario than to any of the other forecast scenarios
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)
and on-system contracts (including past sales to Raft River and the City of Weiser).
Idaho Power system load projections are reported in Table 4 and pictured 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 the system load will increase at an average rate of 0.6 percent per year throughout the forecast period. The high scenario projects load
growth of 1.5 percent per year. Idaho Power has experienced both the high- and low-growth rates
in the past. These scenario forecasts provide a range of projected growth rates that cover
Appendix A—Sales and Load Forecast Idaho Power Company
Page 14 2013 Integrated Resource Plan
approximately 80 percent of the probable outcomes as measured by Idaho Power’s
historical experience.
Table 4. System load growth (aMW)
Growth 2013 2017 2022 2032
Annual Growth Rate
2013–2032
Low ....................................................................... 1,738 1,760 1,826 1,949 0.6%
Expected ............................................................... 1,759 1,842 1,956 2,154 1.1%
High ...................................................................... 1,829 1,972 2,145 2,447 1.5%

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
1982 1987 1992 1997 2002 2007 2012 2017 2022 2027 2032
Weather Adjusted (excluding Astaris)Expected 70th Percentile High Low
Idaho Power Company Appendix A—Sales and Load Forecast
2013 Integrated Resource Plan Page 15
RESIDENTIAL
The expected-case residential load is forecast to increase from 574 aMW in 2013 to 704 aMW in
2032, an average annual compound growth rate of 1.1 percent. In the 70th-percentile scenario, the residential load is forecast to increase from 590 aMW in 2013 to 724 aMW in 2032, matching the expected-case residential growth rate. The residential load forecasts are reported
in Table 5 and shown graphically in Figure 4.
Table 5. Residential load growth (aMW)
Growth 2013 2017 2022 2032
Annual Growth Rate
2013–2032
90th Percentile ................................................................. 623 649 687 763 1.1%
70th Percentile ................................................................. 590 614 650 724 1.1%
Expected Case ................................................................ 574 597 632 704 1.1%

Figure 4. Forecast residential load (aMW)
Sales to residential customers made up 33 percent of Idaho Power’s system sales in 1982 and
36 percent of system sales in 2012. The residential customer proportion of system sales is forecast to be approximately 36 percent in 2032. There were 416,000 residential customers as of December 2012. The number of residential customers is projected to increase to approximately
554,000 by December 2032. The relative customer proportions of Idaho Power’s system
electricity sales are shown in Figure 15.
The average sales per residential customer were 13,700 kWh in 1977. Average sales increased to over 14,800 kWh per residential customer in 1979 before declining to 13,200 kWh in 2001. In 2002 and 2003, residential use per customer dropped dramatically—over 500 kWh per
0
100
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600
700
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900
1,000
1977 1982 1987 1992 1997 2002 2007 2012 2017 2022 2027 2032
Weather Adjusted Expected Case 70th Percentile 90th Percentile
Appendix A—Sales and Load Forecast Idaho Power Company
Page 16 2013 Integrated Resource Plan
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 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 served to slow 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 2032. 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 June 2012 forecast of county housing stock and
demographic data. The residential-customer forecast for 2013 to 2032 shows an average annual
growth rate of 1.5 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
1977 1982 1987 1992 1997 2002 2007 2012 2017 2022 2027 2032
Actual Forecast
Idaho Power Company Appendix A—Sales and Load Forecast
2013 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 schedules considered part of the commercial category are unmetered general-service, street-lighting service, traffic-control signal-lighting service, and dusk-to-dawn customer lighting.
In the expected-case scenario, the commercial load is projected to increase from 446 aMW in
2013 to 549 aMW in 2032. The average annual compound-growth rate of the commercial load is
1.1 percent during the forecast period. As referred to previously, the forecast does not include an assumption for growth from new customers that deviate from historical business failure and startup parameters. As summarized in Table 6, the commercial load in the 70th-percentile
scenario is projected to increase from 451 aMW in 2013 to 556 aMW in 2032. The commercial
load forecasts are illustrated in Figure 6.
Table 6. Commercial load growth (aMW)
Growth 2013 2017 2022 2032 Annual Growth Rate 2013–2032
90th Percentile .................................................................. 463 485 510 572 1.1%
70th Percentile .................................................................. 451 472 496 556 1.1%
Expected Case ................................................................. 446 466 490 549 1.1%

Figure 6. Forecast commercial load (aMW)
As of December 2012, Idaho Power had 66,000 commercial customers. The number of
commercial customers is expected to increase at an average annual growth rate of 1.6 percent,
reaching 90,200 customers by 2032. Commercial customers consumed nearly 17 percent of Idaho Power system sales in 1982 and nearly 28 percent of system sales in 2012.
0
100
200
300
400
500
600
700
1977 1982 1987 1992 1997 2002 2007 2012 2017 2022 2027 2032
Weather Adjusted Expected Case 70th Percentile 90th Percentile
Appendix A—Sales and Load Forecast Idaho Power Company
Page 18 2013 Integrated Resource Plan
The commercial customer proportion of system sales is projected to remain at 28 percent
of system sales by 2032. The relative customer proportions of Idaho Power’s system electricity
sales are shown in Figure 15.
The average consumption per commercial customer increased to a record 67,300 kWh in 2001. However, two years of significantly higher electricity prices combined with a weak national
and service-area economy caused a setback in the growth of commercial use per customer
beginning in 2002. The reduction in electricity prices in June 2003 and a recovery in the
service-area economy slowed the rate of decline in commercial use per customer through 2007.
However, a severe recession in 2008 and 2009 caused commercial use per customer to drop considerably. After flattening out from 2010 to 2012, commercial use per customer is projected
to rise slowly through 2014 as the economy recovers, then continue its downward trend.
The primary reasons for the long-term decline are higher retail electricity prices due to
generating plant additions and DSM program impacts on energy sales. The average
consumption per commercial customer is expected to decrease to approximately 53,500 kWh in 2032. The forecast average annual use per commercial customer is shown in Figure 7.

Figure 7. Forecast commercial use per customer (weather-adjusted kWh)
The commercial-use-per-customer forecast is based on a forecast of the number of commercial
customers and an econometric analysis of commercial-sector sales. The number of commercial
customers being added each year is a direct function of the number of new residential customers
being added. Additionally, the number of residential customers being added is a direct function of the number of new service-area households as derived from Moody’s Analytics June 2012
economic forecast of county housing stock and demographic data. The commercial-customer
forecast for 2013 to 2032 shows an average annual growth rate of 1.6 percent.
The commercial-sales forecast equation considers several factors affecting electricity sales to the
commercial sector. Commercial sales are a function of HDD (wintertime); CDD (summertime); the number of service-area households and service-area employment as derived from
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
1977 1982 1987 1992 1997 2002 2007 2012 2017 2022 2027 2032
Actual Forecast
Hi
Idaho Power Company Appendix A—Sales and Load Forecast
2013 Integrated Resource Plan Page 19
Moody’s Analytics forecasts; and the real price of electricity. The commercial-use-per-customer
forecast is arrived at by dividing the commercial sales forecast, which considers the impacts of
forecast DSM, by the commercial-customer forecast.
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Idaho Power Company Appendix A—Sales and Load Forecast
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IRRIGATION
The irrigation category is made up 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.
Throughout the forecast period, the expected-case irrigation load is forecast to remain flat at
200 aMW from 2013 to 2032, an average annual compound growth rate of 0 percent.
The expected-case, 70th-percentile, and 90th-percentile scenarios forecast no growth in irrigation load from 2013 to 2032. In the 70th-percentile scenario, irrigation load is projected to be 215 aMW in 2013 and 215 aMW in 2032. The individual irrigation load forecasts are reported in
Table 7 and Figure 8, which illustrates the poorer economic conditions and dramatic reduction in
land put into production in the mid-1980s.
Table 7. Irrigation load growth (aMW)
Growth 2013 2017 2022 2032 Annual Growth Rate 2013–2032
90th Percentile .................................................................. 235 235 236 235 0.0%
70th Percentile .................................................................. 215 215 216 215 0.0%
Expected Case ................................................................. 200 200 202 200 0.0%

Figure 8. Forecast irrigation load (aMW)
It is important to understand that the annual average loads in Table 7 and Figure 8 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
0
50
100
150
200
250
300
350
400
1977 1982 1987 1992 1997 2002 2007 2012 2017 2022 2027 2032
Weather Adjusted Expected Case 70th Percentile 90th Percentile
Hi
Appendix A—Sales and Load Forecast Idaho Power Company
Page 22 2013 Integrated Resource Plan
the annual energy is billed in just two months, July and August. During the summer,
hourly irrigation loads can exceed 800 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
30 percent of the energy 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 2013 irrigation sales forecast is slightly higher than the 2011 IRP forecast through 2015,
likely due to recent high commodity prices and changing crop planting patterns. Farmers have
taken advantage of the commodities market by planting increasing levels of acreage. After 2015,
the sales forecast is slightly lower than the previous IRP forecast, primarily due to higher electricity prices influencing demand. 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 2013 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 the 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 1,990,000 MWh in 2000. Idaho Power projects no growth in irrigated acres in the
service area and limited growth in sprinkler irrigation or conversion to sprinkler irrigation.
Irrigation sales represented about 18 percent of weather-normalized Idaho Power system sales in
1982 and reached a maximum proportion of 20 percent of Idaho Power system sales in 1977.
In 2012, the irrigation proportion of system sales was 14 percent due to the much higher relative growth in other customer classes. By 2032, irrigation customers are projected to consume less
than 10 percent of Idaho Power system sales. The irrigation customer load proportion is shown in
Figure 15.
In 1980, Idaho Power had about 10,850 active irrigation accounts. By 2012, the number of active
irrigation accounts had increased to 18,675 and is projected to be nearly 23,000 at the end of the planning period in 2032.
Since 1988, Idaho Power has experienced some growth in the number of irrigation customers,
but very little, if any, 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
Idaho Power Company Appendix A—Sales and Load Forecast
2013 Integrated Resource Plan Page 23
customer. This is because water for furrow irrigation is gravity-drawn from canals and not
pumped from deep, groundwater wells.
Bell Rapids, a large, high-lift cooperative irrigation company that irrigated about 25,000 acres
from 1970 to 2004, was Idaho Power’s largest irrigation customer. The Bell Rapids combined accounts included more than 40 irrigation service points that accounted for approximately 3 to
4 percent of Idaho Power’s annual irrigation sales. In early 2005, the State of Idaho purchased
the water rights from Bell Rapids, which resulted in the loss of Bell Rapids as an irrigation
customer. Prior to 2005, Bell Rapids consumed, on average, 55,000 MWh annually.
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.
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Idaho Power Company Appendix A—Sales and Load Forecast
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INDUSTRIAL
The industrial category is made up of Idaho Power’s large power service (Schedule 19)
customers with monthly metered demands between 1,000 kilowatts (kW) and 20,000 kW. In 1975, Idaho Power had about 70 industrial customers, which represented about 10 percent of Idaho Power’s system sales. By December 2012, the number of industrial customers had risen
to 116, representing approximately 16 percent of system sales. Special contracts are addressed
in the Additional Firm Load section of this document.
In the expected-case forecast, industrial load grows from 267 aMW in 2013 to 367 aMW in 2032, an average annual growth rate of 1.7 percent (Table 8). As a general rule, industrial loads are not weather sensitive, and the forecasts in the 70th and 90th-percentile scenarios are identical
to the expected-case industrial-load scenario. The industrial load forecast is pictured in Figure 9.
Table 8. Industrial load growth (aMW)
Growth 2013 2017 2022 2032 Annual Growth Rate 2013–2032
Expected Case ................................................................. 267 294 319 367 1.7%

Figure 9. Forecast industrial load (aMW)
The industrial energy forecast is based on the most recent (June 2012) national, state, MSA,
and county economic forecasts from Moody’s Analytics and the resulting derived economic forecast for Idaho Power’s service area.
0
50
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150
200
250
300
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450
1977 1982 1987 1992 1997 2002 2007 2012 2017 2022 2027 2032
Actual Expected Case
Appendix A—Sales and Load Forecast Idaho Power Company
Page 26 2013 Integrated Resource Plan
Since rate tariff definitions do not correspond with economic activity types, Idaho Power’s
Schedule 19 customers were categorized, and their historical electricity sales were summarized
by economic activity. This is also true for the large commercial loads, so Schedule 9 primary
and transmission customers’ energy sales were also included for forecasting purposes and later recombined with the commercial-sector sales forecast. The appropriate employment
series (or population time series) were matched to each economic sector or industry group.
Regression models were developed for 16 industry groups to determine the relationship between
historical electricity sales and historical employment, population, and/or other relevant
explanatory variables. The estimated coefficients from the industry group regression models were then applied to the appropriate employment, population, and other relevant drivers,
which resulted in the escalation of electricity sales to the various industry groups over time.
Figure 10 illustrates the 2012 industrial electricity consumption by industry group. By far,
the largest share of electricity was consumed by the food manufacturing sector (47%);
followed by other industry groups (17%); health care (7%); and computer and electronic product manufacturing, education, and other manufacturing (each representing 6%). As Figure 10 shows,
several other industry groups make up the remaining share of the 2012 industrial
electricity consumption.

Figure 10. Industrial electricity consumption by industry group (based on 2012 figures)
Food Manufacturing46.5%
Health Care6.6%Computer and Electronic Product
Manufacturing6.3%
Education6.3%
Other Manufacturing5.7%
Small Offices4.0%
Nonmetallic Mineral Product Manufacturing3.8%Food Sales3.6%Other Industry Groups17.2%
Idaho Power Company Appendix A—Sales and Load Forecast
2013 Integrated Resource Plan Page 27
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 four special-contract customers recognized as firm-load customers. These special-contract customers are Micron Technology,
Simplot Fertilizer, the INL, and Hoku Materials. The contract with Raft River expired on
September 30, 2011.
In the expected-case forecast, additional firm load is expected to increase from 115 aMW in 2013 to 143 aMW in 2032, an average growth rate of 1.1 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 11.
Table 9. Additional firm load growth (aMW)
Growth 2013 2017 2022 2032 Annual Growth Rate 2013–2032
Expected Case ................................................................. 115 121 140 143 1.1%

Figure 11. Forecast additional firm load (aMW)
0
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1977 1982 1987 1992 1997 2002 2007 2012 2017 2022 2027 2032
Actual Expected Case
Appendix A—Sales and Load Forecast Idaho Power Company
Page 28 2013 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, 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 in 2013 and 2014, then stay flat throughout the remainder of the planning. The primary driver of long-term electricity sales growth at Simplot Fertilizer is Moody’s Analytics forecast of gross product in the pesticide,
fertilizer, and other agricultural chemical manufacturing segment for the Pocatello MSA.
Idaho National Laboratory
The DOE provided an energy-consumption and peak-demand forecast through 2032 for
the INL. The forecast calls for loads to slowly rise through 2015, remain flat for five years,
rise dramatically through 2022, and stay at the higher level throughout the remainder of the
forecast period.
Hoku Materials
The sales and load forecast prepared for the 2011 IRP reflected the expected increase in
demand for energy and peak capacity of Idaho Power’s most recent special-contract customer, Hoku Materials, located in Pocatello, Idaho. However, since the 2011 IRP, Hoku Materials was
unable to complete the construction of its manufacturing facility and execute on its contract to
take service under the special-contract tariff. For the 2013 IRP, Idaho Power has assumed that
Hoku Materials will not come on-line, and the 74 aMW of energy and 82 MW of peak demand
originally anticipated are excluded from this sales and load forecast.
“Special” Contract
In the 2011 IRP sales and load forecast, there was an additional customer referred to as
“Special” included with the additional firm load category (special contracts) even though no long-term contract had been fully executed. When that forecast was prepared (August 2010),
several interested parties had taken significant steps toward the development and location of their
businesses within Idaho Power’s service area. It was determined at that time there was a real
possibility of the new large load materializing. However, since the 2011 IRP, the likelihood of
the new large load diminished. For the 2013 IRP, Idaho Power has assumed this “Special” contract will not come on-line, and the 54 aMW of energy and 60 MW of peak demand originally anticipated are excluded from this sales and load forecast.
Idaho Power Company Appendix A—Sales and Load Forecast
2013 Integrated Resource Plan Page 29
COMPANY SYSTEM PEAK
System peak load includes the sum of individual 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 3,245 MW, recorded on Thursday, July 12,
2012, at 4:00 p.m. The previous summer peak demand was 3,214 MW and occurred on Monday,
June 30, 2008, at 3:00 p.m. 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 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
3,344 MW in 2013 to 4,365 MW in the year 2032, an average growth rate of 1.4 percent per year
over the planning period (Table 10). In the 95th-percentile forecast, the system summer peak load
is expected to increase from 3,382 MW in 2013 to 4,418 MW in 2032. The three scenarios of
projected system summer peak load are illustrated in Figure 12. 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 2013 2017 2022 2032 Annual Growth Rate 2013–2032
95th Percentile .................................................................. 3,382 3,596 3,881 4,418 1.4%
90th Percentile .................................................................. 3,344 3,555 3,835 4,365 1.4%
50th Percentile .................................................................. 3,189 3,387 3,651 4,147 1.4%

Figure 12. 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
1977 1982 1987 1992 1997 2002 2007 2012 2017 2022 2027 2032
Actual less Astaris Actual 50th Percentile 90th Percentile 95th Percentile
Appendix A—Sales and Load Forecast Idaho Power Company
Page 30 2013 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 13, the historical system winter peak load is much more
variable than the summer system peak load. This is because the variability of peak-day
temperatures in winter months is far greater 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
2,585 MW in 2013 to 3,020 MW in 2032, an average growth rate of 0.8 percent per year over
the planning period (Table 11). In the 95th-percentile forecast, the system winter peak load is expected to increase from 2,683 MW in 2013 to 3,118 MW in 2032, an average growth rate of
0.8 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 2013 2017 2022 2032 Annual Growth Rate 2013–2032
95th Percentile .................................................................. 2,683 2,765 2,901 3,118 0.8%
90th Percentile .................................................................. 2,585 2,668 2,803 3,020 0.8%
50th Percentile .................................................................. 2,301 2,384 2,520 2,737 0.9%

Figure 13. Forecast system winter peak (MW)

1,000
1,300
1,600
1,900
2,200
2,500
2,800
3,100
3,400
1977-78 1983-84 1989-90 1995-96 2001-02 2007-08 2013-14 2019-20 2025-26 2031-32
Actual less Astaris Actual 50th Percentile 90th Percentile 95th Percentile
Idaho Power Company Appendix A—Sales and Load Forecast
2013 Integrated Resource Plan Page 31
COMPANY SYSTEM LOAD
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) 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 most recent Moody’s Analytics
economic forecast for the nation, state, MSAs, and counties in the service area and represents
Idaho Power’s most probable load growth during the planning period. The expected-case forecast system load growth rate averages 1.1 percent per year from 2013 to 2032. Company system load projections are reported in Table 12 and shown in Figure 14.
In the expected-case forecast, the company system load is expected to increase from 1,759 aMW
in 2013 to 2,154 aMW in 2032. In the 70th-percentile forecast, the company system load is
expected to increase from 1,800 aMW in 2013 to 2,201 aMW by 2032, an average growth rate of 1.1 percent per year over the planning period (Table 12).
Table 12. System load growth (aMW)
Growth 2013 2017 2022 2032 Annual Growth Rate 2013–2032
90th Percentile .................................................................. 1,872 1,959 2,078 2,284 1.1%
70th Percentile .................................................................. 1,800 1,884 2,000 2,201 1.1%
Expected Case ................................................................. 1,759 1,842 1,956 2,154 1.1%

Figure 14. Forecast system load (aMW)
700
1,000
1,300
1,600
1,900
2,200
2,500
2,800
1977 1982 1987 1992 1997 2002 2007 2012 2017 2022 2027 2032
WA less Astaris Weather Adjusted Expected Case 70th Percentile 90th Percentile
Appendix A—Sales and Load Forecast Idaho Power Company
Page 32 2013 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 has been Idaho Power’s
largest individual customer and, in some past years, averaged nearly 200 aMW each month.
In April 2002, the special contract between Astaris and Idaho Power was terminated. Without the dampening effects of Astaris on historical system load growth, the system load more accurately
portrays the underlying general business growth trend within the service area.
Accompanied by an outlook of moderate economic growth for Idaho Power’s service area
throughout the forecast period, Appendix A—Sales and Load Forecast projects continued growth
in Idaho Power’s system load. Total load is made up of system load plus long-term, firm, off-system contracts. At this time, there are no contracts in effect to provide long-term firm
energy off-system.
The composition of system company electricity sales by year is shown in Figure 15.
Residential sales are forecast to be nearly 23 percent higher in 2032, gaining 1.1 million MWh
over 2013. Commercial sales are also expected to be 23 percent higher or 0.9 million MWh above 2013 followed by industrial (38 percent higher or 0.9 million additional MWh)
and irrigation (only 0.2 percent higher in 2032 than 2013). Electricity sales to Astaris ended
in April 2002.

Figure 15. 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 2013 to 2032.

0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
20,000
1982 1987 1992 1997 2002 2007 2012 2017 2022 2027 2032
Residential Commercial Industrial Irrigation Additional Firm Sales Astaris
Idaho Power Company Appendix A—Sales and Load Forecast
2013 Integrated Resource Plan Page 33
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 34 2013 Integrated Resource Plan
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Idaho Power Company Appendix A—Sales and Load Forecast
2013 Integrated Resource Plan Page 35
ENERGY EFFICIENCY AND DEMAND RESPONSE
Energy efficiency and demand response impacts are treated differently in the forecasting and
planning process. Energy efficiency impacts (reductions) 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 industrial and irrigation customers is not directly surveyed and collected by
the DOE; therefore, the 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 utility acquisition, recognizing that historical trends are embedded in the actual sales data (which serves 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 actual 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 sister utility
acquisitions to ensure the models are correctly capturing all energy savings.
Energy savings from energy efficiency programs are typically measured and reported at the point
of delivery (customer’s meter). Therefore, energy efficiency savings are increased by the amount of energy lost in transmitting the electricity from the generation source to the customer’s meter.

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 36 2013 Integrated Resource Plan
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 the 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. In the
next planning cycle, the impact of new committed programs will be considered when updating
the individual class-level sales forecasts.
Demand Response
Beginning with the 2009 IRP, demand response programs have been 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.
Demand response programs are treated as supply-side resources in the 2013 IRP and 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. Because energy efficiency programs also result in a reduction to peak demand,
there is a component of peak-hour load reduction integrated into the sales and load forecast.
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 2012 Annual Report.

Idaho Power Company Appendix A1. Historical and Projected Sales and Load
2013 Integrated Resource Plan Page 37
Appendix A1. Historical and Projected Sales and Load
Residential Load
Historical Residential Sales and Load, 1972–2012 (weather adjusted)
Year Average Customers Percent Change kWh per Customer Billed Sales (thousands of MWh) Percent Change Average Load (aMW)
1972 145,208 – 10,959 1,591 – 184
1973 152,957 5.3% 11,537 1,765 10.9% 203
1974 160,151 4.7% 12,066 1,932 9.5% 223
1975 167,622 4.7% 12,955 2,172 12.4% 250
1976 175,720 4.8% 13,455 2,364 8.9% 271
1977 184,561 5.0% 13,686 2,526 6.8% 290
1978 194,650 5.5% 14,235 2,771 9.7% 321
1979 202,982 4.3% 14,779 3,000 8.3% 342
1980 209,629 3.3% 14,585 3,057 1.9% 348
1981 213,579 1.9% 14,339 3,063 0.2% 349
1982 216,696 1.5% 14,395 3,119 1.9% 356
1983 219,849 1.5% 14,375 3,160 1.3% 363
1984 222,695 1.3% 14,146 3,150 (0.3%) 357
1985 225,185 1.1% 14,049 3,164 0.4% 363
1986 227,081 0.8% 14,256 3,237 2.3% 368
1987 228,868 0.8% 14,097 3,226 (0.3%) 366
1988 230,771 0.8% 14,352 3,312 2.7% 378
1989 233,370 1.1% 14,336 3,346 1.0% 383
1990 238,117 2.0% 14,277 3,400 1.6% 393
1991 243,207 2.1% 14,566 3,542 4.2% 402
1992 249,767 2.7% 14,146 3,533 (0.3%) 408
1993 258,271 3.4% 14,172 3,660 3.6% 412
1994 267,854 3.7% 14,002 3,750 2.5% 434
1995 277,131 3.5% 14,004 3,881 3.5% 438
1996 286,227 3.3% 13,734 3,931 1.3% 455
1997 294,674 3.0% 13,682 4,032 2.6% 463
1998 303,300 2.9% 13,744 4,169 3.4% 476
1999 312,901 3.2% 13,620 4,262 2.2% 488
2000 322,402 3.0% 13,407 4,322 1.4% 500
2001 331,009 2.7% 13,160 4,356 0.8% 476
2002 339,764 2.6% 12,637 4,294 (1.4%) 488
2003 349,219 2.8% 12,653 4,419 2.9% 507
2004 360,462 3.2% 12,686 4,573 3.5% 524
2005 373,602 3.6% 12,684 4,739 3.6% 543
2006 387,707 3.8% 12,878 4,993 5.4% 568
2007 397,286 2.5% 12,924 5,135 2.8% 585
2008 402,520 1.3% 12,875 5,182 0.9% 594
2009 405,144 0.7% 12,672 5,134 (0.9%) 584
2010 407,551 0.6% 12,461 5,078 (1.1%) 582
2011 409,786 0.5% 12,363 5,066 (0.2%) 577
2012 413,610 0.9% 12,274 5,077 0.2% 581

Appendix A1. Historical and Projected Sales and Load Idaho Power Company
Page 38 2013 Integrated Resource Plan
Residential Load
Projected Residential Sales and Load, 2013–2032
Year Average Customers Percent Change kWh per Customer Billed Sales (thousands of MWh) Percent Change Average Load (aMW)
2013 417,852 1.0% 12,025 5,025 (1.0%) 574
2014 422,850 1.2% 11,954 5,055 0.6% 577
2015 429,685 1.6% 11,783 5,063 0.2% 579
2016 438,746 2.1% 11,695 5,131 1.3% 587
2017 448,379 2.2% 11,644 5,221 1.8% 597
2018 457,313 2.0% 11,588 5,299 1.5% 606
2019 465,250 1.7% 11,545 5,371 1.4% 614
2020 472,652 1.6% 11,480 5,426 1.0% 620
2021 479,844 1.5% 11,412 5,476 0.9% 626
2022 486,853 1.5% 11,363 5,532 1.0% 632
2023 493,741 1.4% 11,342 5,600 1.2% 640
2024 500,509 1.4% 11,294 5,653 0.9% 646
2025 507,171 1.3% 11,235 5,698 0.8% 651
2026 513,749 1.3% 11,230 5,769 1.2% 659
2027 520,202 1.3% 11,230 5,842 1.3% 667
2028 526,553 1.2% 11,199 5,897 0.9% 674
2029 532,781 1.2% 11,197 5,966 1.2% 682
2030 538,901 1.1% 11,211 6,042 1.3% 690
2031 544,944 1.1% 11,203 6,105 1.0% 697
2032 550,883 1.1% 11,189 6,164 1.0% 704

Idaho Power Company Appendix A1. Historical and Projected Sales and Load
2013 Integrated Resource Plan Page 39
Commercial Load
Historical Commercial Sales and Load, 1972–2012 (weather adjusted)
Year Average Customers Percent Change kWh per Customer Billed Sales (thousands of MWh) Percent Change Average Load (aMW)
1972 22,585 – 46,141 1,042 – 120
1973 23,286 3.1% 48,145 1,121 7.6% 128
1974 24,096 3.5% 49,028 1,181 5.4% 136
1975 25,045 3.9% 51,217 1,283 8.6% 147
1976 26,034 3.9% 52,513 1,367 6.6% 157
1977 27,112 4.1% 52,416 1,421 3.9% 162
1978 27,831 2.7% 52,476 1,460 2.8% 169
1979 28,087 0.9% 56,389 1,584 8.4% 180
1980 28,797 2.5% 54,145 1,559 (1.6%) 178
1981 29,567 2.7% 54,286 1,605 2.9% 184
1982 30,167 2.0% 54,127 1,633 1.7% 186
1983 30,776 2.0% 52,676 1,621 (0.7%) 186
1984 31,554 2.5% 53,383 1,684 3.9% 191
1985 32,418 2.7% 53,989 1,750 3.9% 201
1986 33,208 2.4% 53,869 1,789 2.2% 204
1987 33,975 2.3% 53,357 1,813 1.3% 206
1988 34,723 2.2% 54,409 1,889 4.2% 216
1989 35,638 2.6% 55,451 1,976 4.6% 227
1990 36,785 3.2% 55,844 2,054 3.9% 236
1991 37,922 3.1% 56,164 2,130 3.7% 243
1992 39,022 2.9% 56,339 2,198 3.2% 253
1993 40,047 2.6% 57,951 2,321 5.6% 263
1994 41,629 4.0% 58,181 2,422 4.4% 280
1995 43,165 3.7% 58,742 2,536 4.7% 288
1996 44,995 4.2% 62,048 2,792 10.1% 323
1997 46,819 4.1% 62,019 2,904 4.0% 333
1998 48,404 3.4% 62,722 3,036 4.6% 347
1999 49,430 2.1% 64,191 3,173 4.5% 363
2000 50,117 1.4% 65,975 3,306 4.2% 383
2001 51,501 2.8% 67,339 3,468 4.9% 383
2002 52,915 2.7% 64,788 3,428 (1.1%) 390
2003 54,194 2.4% 64,243 3,482 1.6% 399
2004 55,577 2.6% 64,042 3,559 2.2% 407
2005 57,145 2.8% 63,517 3,630 2.0% 415
2006 59,050 3.3% 63,425 3,745 3.2% 426
2007 61,640 4.4% 63,336 3,904 4.2% 445
2008 63,492 3.0% 62,200 3,949 1.2% 451
2009 64,151 1.0% 59,488 3,816 (3.4%) 436
2010 64,421 0.4% 58,820 3,789 (0.7%) 434
2011 64,921 0.8% 58,285 3,784 (0.1%) 432
2012 65,599 1.0% 58,941 3,866 2.2% 442

Appendix A1. Historical and Projected Sales and Load Idaho Power Company
Page 40 2013 Integrated Resource Plan
Commercial Load
Projected Commercial Sales and Load, 2013–2032
Year Average Customers Percent Change kWh per Customer Billed Sales (thousands of MWh) Percent Change Average Load (aMW)
2013 66,489 1.4% 58,657 3,900 0.9% 446
2014 67,430 1.4% 58,737 3,961 1.6% 452
2015 68,612 1.8% 58,249 3,997 0.9% 457
2016 70,122 2.2% 57,661 4,043 1.2% 462
2017 71,686 2.2% 56,953 4,083 1.0% 466
2018 73,199 2.1% 56,250 4,117 0.9% 470
2019 74,579 1.9% 55,754 4,158 1.0% 475
2020 75,873 1.7% 55,392 4,203 1.1% 480
2021 77,131 1.7% 55,025 4,244 1.0% 485
2022 78,357 1.6% 54,730 4,288 1.0% 490
2023 79,565 1.5% 54,520 4,338 1.2% 495
2024 80,754 1.5% 54,202 4,377 0.9% 500
2025 81,925 1.4% 53,864 4,413 0.8% 504
2026 83,082 1.4% 53,741 4,465 1.2% 510
2027 84,220 1.4% 53,642 4,518 1.2% 516
2028 85,343 1.3% 53,466 4,563 1.0% 521
2029 86,450 1.3% 53,429 4,619 1.2% 528
2030 87,540 1.3% 53,470 4,681 1.3% 535
2031 88,619 1.2% 53,491 4,740 1.3% 542
2032 89,685 1.2% 53,547 4,802 1.3% 549

Idaho Power Company Appendix A1. Historical and Projected Sales and Load
2013 Integrated Resource Plan Page 41
Irrigation Load
Historical Irrigation Sales and Load, 1972–2012 (weather adjusted)
Year
Maximum Active
Customers
Percent
Change
kWh per
Customer
Billed Sales
(thousands of MWh)
Percent
Change
Average
Load (aMW)
1972 7,815 – 132,292 1,034 – 118
1973 8,341 6.7% 141,030 1,176 13.8% 134
1974 8,971 7.6% 147,698 1,325 12.6% 151
1975 9,480 5.7% 153,957 1,460 10.2% 167
1976 9,936 4.8% 155,406 1,544 5.8% 176
1977 10,238 3.0% 163,266 1,672 8.3% 191
1978 10,476 2.3% 154,006 1,613 (3.5%) 184
1979 10,711 2.2% 161,705 1,732 7.4% 197
1980 10,854 1.3% 155,740 1,690 (2.4%) 192
1981 11,248 3.6% 164,533 1,851 9.5% 211
1982 11,312 0.6% 151,369 1,712 (7.5%) 196
1983 11,133 (1.6%) 142,865 1,591 (7.1%) 182
1984 11,375 2.2% 132,933 1,512 (4.9%) 172
1985 11,576 1.8% 134,849 1,561 3.2% 178
1986 11,308 (2.3%) 134,121 1,517 (2.8%) 173
1987 11,254 (0.5%) 128,532 1,446 (4.6%) 165
1988 11,378 1.1% 137,237 1,561 7.9% 178
1989 11,957 5.1% 137,982 1,650 5.7% 188
1990 12,340 3.2% 146,128 1,803 9.3% 206
1991 12,484 1.2% 135,557 1,692 (6.2%) 193
1992 12,809 2.6% 140,744 1,803 6.5% 205
1993 13,078 2.1% 125,294 1,639 (9.1%) 187
1994 13,559 3.7% 130,325 1,767 7.8% 202
1995 13,679 0.9% 125,349 1,715 (3.0%) 196
1996 14,074 2.9% 123,944 1,744 1.7% 199
1997 14,383 2.2% 115,552 1,662 (4.7%) 190
1998 14,695 2.2% 114,918 1,689 1.6% 193
1999 14,912 1.5% 117,715 1,755 3.9% 200
2000 15,253 2.3% 126,625 1,931 10.0% 220
2001 15,522 1.8% 116,328 1,806 (6.5%) 206
2002 15,840 2.0% 110,674 1,753 (2.9%) 200
2003 16,020 1.1% 110,784 1,775 1.2% 203
2004 16,297 1.7% 108,574 1,769 (0.3%) 201
2005 16,936 3.9% 98,823 1,674 (5.4%) 191
2006 17,062 0.7% 97,105 1,657 (1.0%) 189
2007 17,001 (0.4%) 105,867 1,800 8.6% 205
2008 17,428 2.5% 109,360 1,906 5.9% 217
2009 17,708 1.6% 100,337 1,777 (6.8%) 203
2010 17,846 0.8% 99,895 1,783 0.3% 204
2011 18,292 2.5% 97,124 1,777 (0.3%) 203
2012 18,675 2.1% 103,703 1,937 9.0% 220

Appendix A1. Historical and Projected Sales and Load Idaho Power Company
Page 42 2013 Integrated Resource Plan
Irrigation Load
Projected Irrigation Sales and Load, 2013–2032
Year
Maximum Active
Customers
Percent
Change
kWh per
Customer
Billed Sales
(thousands of MWh)
Percent
Change
Average
Load (aMW)
2013 18,890 1.2% 92,719 1,751 (9.6%) 200
2014 19,142 1.3% 92,074 1,762 0.6% 201
2015 19,396 1.3% 91,204 1,769 0.4% 202
2016 19,645 1.3% 89,128 1,751 (1.0%) 199
2017 19,899 1.3% 87,928 1,750 (0.1%) 200
2018 20,152 1.3% 87,142 1,756 0.4% 200
2019 20,404 1.3% 86,281 1,760 0.2% 201
2020 20,655 1.2% 85,477 1,766 0.3% 201
2021 20,909 1.2% 84,582 1,769 0.2% 202
2022 21,160 1.2% 83,429 1,765 (0.2%) 202
2023 21,413 1.2% 82,407 1,765 0.0% 201
2024 21,664 1.2% 81,620 1,768 0.2% 201
2025 21,917 1.2% 80,447 1,763 (0.3%) 201
2026 22,172 1.2% 79,028 1,752 (0.6%) 200
2027 22,423 1.1% 78,263 1,755 0.2% 200
2028 22,675 1.1% 77,568 1,759 0.2% 200
2029 22,926 1.1% 76,458 1,753 (0.3%) 200
2030 23,180 1.1% 75,656 1,754 0.0% 200
2031 23,434 1.1% 75,013 1,758 0.2% 201
2032 23,684 1.1% 74,129 1,756 (0.1%) 200

Idaho Power Company Appendix A1. Historical and Projected Sales and Load
2013 Integrated Resource Plan Page 43
Industrial Load
Historical Industrial Sales and Load, 1972–2012 (weather adjusted)
Year Average Customers Percent Change kWh per Customer Billed Sales (thousands of MWh) Percent Change Average Load (aMW)
1972 56 – 10,944,714 615 – 71
1973 63 12.3% 10,889,056 687 11.7% 79
1974 65 2.2% 11,464,249 739 7.6% 84
1975 71 10.5% 11,014,121 785 6.1% 91
1976 73 3.0% 11,681,540 858 9.3% 99
1977 85 15.1% 10,988,826 929 8.3% 106
1978 99 17.6% 9,786,753 972 4.7% 111
1979 109 9.6% 9,989,158 1,087 11.8% 126
1980 112 2.7% 9,894,706 1,106 1.7% 125
1981 118 5.7% 9,718,723 1,148 3.9% 132
1982 122 3.5% 9,504,283 1,162 1.2% 133
1983 122 (0.3%) 9,797,522 1,194 2.7% 138
1984 124 1.5% 10,369,789 1,282 7.4% 147
1985 125 1.2% 10,844,888 1,357 5.9% 155
1986 129 2.7% 10,550,145 1,357 (0.1%) 155
1987 134 4.1% 11,006,455 1,474 8.7% 169
1988 133 (1.0%) 11,660,183 1,546 4.9% 177
1989 132 (0.6%) 12,091,482 1,594 3.1% 183
1990 132 0.2% 12,584,200 1,662 4.3% 191
1991 135 2.5% 12,699,665 1,719 3.4% 196
1992 140 3.4% 12,650,945 1,770 3.0% 203
1993 141 0.5% 13,179,585 1,854 4.7% 212
1994 143 1.7% 13,616,608 1,948 5.1% 223
1995 120 (15.9%) 16,793,437 2,021 3.7% 230
1996 103 (14.4%) 18,774,093 1,934 (4.3%) 221
1997 106 2.7% 19,309,504 2,042 5.6% 235
1998 111 4.6% 19,378,734 2,145 5.0% 244
1999 108 (2.3%) 19,985,029 2,160 0.7% 247
2000 107 (0.8%) 20,433,299 2,191 1.5% 250
2001 111 3.5% 20,618,361 2,289 4.4% 260
2002 111 (0.1%) 19,441,876 2,156 (5.8%) 246
2003 112 1.0% 19,950,866 2,234 3.6% 255
2004 117 4.3% 19,417,310 2,269 1.5% 259
2005 126 7.9% 18,645,220 2,351 3.6% 270
2006 127 1.0% 18,255,385 2,325 (1.1%) 265
2007 123 (3.6%) 19,275,551 2,366 1.8% 270
2008 119 (3.1%) 19,412,391 2,308 (2.4%) 261
2009 124 4.0% 17,987,570 2,224 (3.6%) 254
2010 121 (2.0%) 18,404,875 2,232 0.3% 254
2011 120 (1.1%) 18,586,468 2,229 (0.1%) 254
2012 115 (4.2%) 19,746,525 2,269 1.8% 260

Appendix A1. Historical and Projected Sales and Load Idaho Power Company
Page 44 2013 Integrated Resource Plan
Industrial Load
Projected Industrial Sales and Load, 2013–2032
Year Average Customers Percent Change kWh per Customer Billed Sales (thousands of MWh) Percent Change Average Load (aMW)
2013 116 0.9% 20,123,969 2,334 2.9% 267
2014 117 0.9% 20,531,410 2,402 2.9% 275
2015 118 0.9% 20,904,644 2,467 2.7% 282
2016 121 2.5% 20,855,283 2,523 2.3% 288
2017 121 0.0% 21,229,207 2,569 1.8% 294
2018 123 1.7% 21,215,736 2,610 1.6% 298
2019 124 0.8% 21,400,507 2,654 1.7% 303
2020 125 0.8% 21,591,980 2,699 1.7% 308
2021 126 0.8% 21,777,074 2,744 1.7% 314
2022 128 1.6% 21,782,963 2,788 1.6% 319
2023 130 1.6% 21,787,965 2,832 1.6% 324
2024 131 0.8% 21,953,791 2,876 1.5% 328
2025 131 0.0% 22,268,240 2,917 1.4% 333
2026 133 1.5% 22,264,535 2,961 1.5% 338
2027 133 0.0% 22,596,372 3,005 1.5% 343
2028 135 1.5% 22,573,943 3,047 1.4% 347
2029 136 0.7% 22,727,071 3,091 1.4% 353
2030 138 1.5% 22,713,855 3,135 1.4% 358
2031 139 0.7% 22,862,159 3,178 1.4% 363
2032 140 0.7% 23,014,399 3,222 1.4% 367

Idaho Power Company Appendix A1. Historical and Projected Sales and Load
2013 Integrated Resource Plan Page 45
Additional Firm Sales and Load*
Historical Additional Firm Sales and Load, 1972–2012
Year Billed Sales (thousands of MWh) Percent Change Average Load (aMW)
1972 284 – 32
1973 291 2.3% 33
1974 282 (2.9%) 32
1975 314 11.2% 36
1976 289 (8.1%) 33
1977 311 7.8% 36
1978 357 14.8% 41
1979 373 4.4% 43
1980 360 (3.5%) 41
1981 376 4.6% 43
1982 368 (2.4%) 42
1983 425 15.6% 49
1984 466 9.6% 53
1985 471 1.1% 54
1986 482 2.4% 55
1987 502 4.2% 57
1988 530 5.6% 60
1989 671 26.5% 77
1990 625 (6.9%) 71
1991 661 5.8% 75
1992 680 2.9% 77
1993 689 1.3% 79
1994 741 7.5% 85
1995 878 18.6% 100
1996 989 12.6% 113
1997 1,048 6.0% 120
1998 1,113 6.2% 127
1999 1,122 0.8% 128
2000 1,143 1.9% 130
2001 1,118 (2.1%) 128
2002 1,139 1.9% 130
2003 1,120 (1.7%) 128
2004 1,157 3.3% 132
2005 1,175 1.6% 134
2006 1,189 1.2% 136
2007 1,141 (4.0%) 130
2008 1,114 (2.4%) 127
2009 965 (13.4%) 110
2010 907 (6.0%) 104
2011 906 0.0% 103
2012 862 (4.8%) 98
*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 46 2013 Integrated Resource Plan
Additional Firm Sales and Load*
Projected Additional Firm Sales and Load, 2013–2032
Year Billed Sales (thousands of MWh) Percent Change Average Load (aMW)
2013 1,010 17.1% 115
2014 1,025 1.5% 117
2015 1,053 2.7% 120
2016 1,053 0.1% 120
2017 1,062 0.8% 121
2018 1,060 (0.3%) 121
2019 1,068 0.8% 122
2020 1,115 4.4% 127
2021 1,193 7.0% 136
2022 1,229 3.0% 140
2023 1,234 0.4% 141
2024 1,231 (0.2%) 140
2025 1,234 0.2% 141
2026 1,228 (0.5%) 140
2027 1,228 0.0% 140
2028 1,217 (0.9%) 139
2029 1,212 (0.5%) 138
2030 1,268 4.6% 145
2031 1,262 (0.5%) 144
2032 1,257 (0.4%) 143
*Includes Micron Technology, Simplot Fertilizer, and the INL

Idaho Power Company Appendix A1. Historical and Projected Sales and Load
2013 Integrated Resource Plan Page 47
Company System Load (excluding Astaris)
Historical Company System Sales and Load, 1972–2012 (weather adjusted)
Year Billed Sales (thousands of MWh) Percent Change Average Load (aMW)
1972 4,566 – 577
1973 5,040 10.4% 635
1974 5,461 8.4% 690
1975 6,012 10.1% 760
1976 6,422 6.8% 810
1977 6,858 6.8% 863
1978 7,174 4.6% 910
1979 7,776 8.4% 977
1980 7,773 0.0% 974
1981 8,043 3.5% 1,012
1982 7,994 (0.6%) 1,004
1983 7,991 0.0% 1,009
1984 8,095 1.3% 1,012
1985 8,303 2.6% 1,045
1986 8,382 0.9% 1,050
1987 8,462 1.0% 1,059
1988 8,839 4.5% 1,108
1989 9,237 4.5% 1,161
1990 9,544 3.3% 1,206
1991 9,744 2.1% 1,219
1992 9,985 2.5% 1,259
1993 10,163 1.8% 1,266
1994 10,628 4.6% 1,344
1995 11,030 3.8% 1,373
1996 11,390 3.3% 1,437
1997 11,688 2.6% 1,471
1998 12,151 4.0% 1,522
1999 12,472 2.6% 1,565
2000 12,895 3.4% 1,628
2001 13,037 1.1% 1,594
2002 12,771 (2.0%) 1,596
2003 13,030 2.0% 1,637
2004 13,327 2.3% 1,673
2005 13,568 1.8% 1,703
2006 13,909 2.5% 1,739
2007 14,346 3.1% 1,796
2008 14,460 0.8% 1,813
2009 13,917 (3.8%) 1,744
2010 13,789 (0.9%) 1,734
2011 13,762 (0.2%) 1,725
2012 14,011 1.8% 1,760

Appendix A1. Historical and Projected Sales and Load Idaho Power Company
Page 48 2013 Integrated Resource Plan
Company System Load (including Astaris)
Historical Company System Sales and Load, (1972–2012) (weather adjusted) Astaris Sales and Load (1972–2002) (weather adjusted)
Year Billed Sales (thousands of MWh) Percent Change Average Load (aMW) Astaris Sales (thousands of MWh) Percent Change Average Load (aMW)
1972 6,385 – 794 1,819 – 207
1973 6,685 4.7% 832 1,645 (9.6%) 188
1974 7,104 6.3% 887 1,643 (0.1%) 188
1975 7,569 6.6% 946 1,557 (5.3%) 178
1976 7,997 5.6% 998 1,575 1.2% 179
1977 8,276 3.5% 1,033 1,418 (10.0%) 162
1978 8,716 5.3% 1,094 1,542 8.8% 176
1979 9,170 5.2% 1,144 1,395 (9.6%) 159
1980 9,286 1.3% 1,155 1,513 8.5% 172
1981 9,677 4.2% 1,208 1,634 8.0% 186
1982 9,548 (1.3%) 1,191 1,554 (4.9%) 177
1983 9,600 0.5% 1,202 1,610 3.6% 184
1984 9,796 2.0% 1,215 1,701 5.7% 194
1985 9,917 1.2% 1,239 1,614 (5.1%) 184
1986 9,935 0.2% 1,236 1,554 (3.7%) 177
1987 10,154 2.2% 1,262 1,692 8.9% 193
1988 10,474 3.2% 1,303 1,635 (3.4%) 186
1989 10,940 4.4% 1,365 1,703 4.2% 194
1990 11,149 1.9% 1,398 1,604 (5.8%) 183
1991 11,353 1.8% 1,412 1,609 0.3% 184
1992 11,555 1.8% 1,446 1,570 (2.4%) 179
1993 11,600 0.4% 1,438 1,437 (8.4%) 164
1994 12,048 3.9% 1,514 1,420 (1.2%) 162
1995 12,597 4.6% 1,561 1,567 10.4% 179
1996 13,079 3.8% 1,639 1,689 7.8% 192
1997 13,315 1.8% 1,666 1,628 (3.6%) 186
1998 13,424 0.8% 1,674 1,273 (21.8%) 145
1999 13,523 0.7% 1,691 1,051 (17.4%) 120
2000 13,949 3.1% 1,754 1,054 0.3% 120
2001 13,695 (1.8%) 1,673 658 (37.5%) 75
2002 12,782 (6.7%) 1,597 11 (98.3%) 1
2003 13,030 1.9% 1,637 0 (100.0%) 0
2004 13,327 2.3% 1,673 0 0.0% 0
2005 13,568 1.8% 1,703 0 0.0% 0
2006 13,909 2.5% 1,739 0 0.0% 0
2007 14,346 3.1% 1,796 0 0.0% 0
2008 14,460 0.8% 1,813 0 0.0% 0
2009 13,917 (3.8%) 1,744 0 0.0% 0
2010 13,789 (0.9%) 1,734 0 0.0% 0
2011 13,762 (0.2%) 1,725 0 0.0% 0
2012 14,011 1.8% 1,760 0 0.0% 0

Idaho Power Company Appendix A1. Historical and Projected Sales and Load
2013 Integrated Resource Plan Page 49
Company System Load
Projected Company System Sales and Load, 2013–2032
Year Billed Sales (thousands of MWh) Percent Change Average Load (aMW)
2013 14,020 0.1% 1,759
2014 14,205 1.3% 1,782
2015 14,348 1.0% 1,800
2016 14,502 1.1% 1,818
2017 14,684 1.3% 1,842
2018 14,842 1.1% 1,862
2019 15,011 1.1% 1,883
2020 15,208 1.3% 1,906
2021 15,426 1.4% 1,934
2022 15,603 1.1% 1,956
2023 15,769 1.1% 1,977
2024 15,905 0.9% 1,992
2025 16,025 0.8% 2,009
2026 16,176 0.9% 2,028
2027 16,348 1.1% 2,049
2028 16,483 0.8% 2,065
2029 16,640 1.0% 2,087
2030 16,879 1.4% 2,116
2031 17,043 1.0% 2,137
2032 17,201 0.9% 2,154

Appendix A1. Historical and Projected Sales and Load Idaho Power Company
Page 50 2013 Integrated Resource Plan
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