20110630Appendix A.pdf

Idaho Power Company Appendix A—Sales and Load Forecast
2011 IRP SALES AND LOAD FORECAST
Average Load
The 2011 IRP average system load forecast is lower initially than the 2009 IRP average system load
forecast.However,after 2015,the 2011 IRP forecast is higher in all remaining years of the forecast
period.The recovery in the national and service-area economy is expected to cause load growth to
steadily revive.In addition,the lowered expectations in existing and committed energy efficiency
measures,combined with retail electricity prices that incorporate much-reduced impact of carbon on
Idaho Power’s retail electricity prices,result in an increase of forecast average loads.Significant factors
and considerations that influenced the outcome of the 2011 IRP load forecast include the following:
•The retail electricity price forecast used to prepare the Appendix A—Sales and LoadForecast in
the 2009 IRP reflected the fixed and variable costs of integrating the resources identified by the
2006 IRP preferred portfolio,including the expected cost of carbon emissions.When compared
to the electricity price forecast used to prepare the Appendix A—Sales and Load Forecast,
the 2009 IRP price forecast yielded significantly higher future electricity prices.The price
forecast difference is primarily the result of differing carbon cost assumptions between the
two forecasts.The 2009 IRP retail electricity price forecast assumed a carbon tax scenario
(from the 2006 IRP),and the 2011 IRP electricity price forecast assumed a cap-and-trade carbon
scenario (from the 2009 IRP).Under the cap-and-trade carbon scenario,Idaho Power curtailed
carbon emissions from coal units to comply with target emissions.The carbon assumptions from
the 2006 IRP is the driver for the 2011 IRP’s retail electricity price forecasts.
•The sales and load forecast reflects the increased expected demand for energy and peak capacity
of Idaho Power’s newest special-contract customer,Hoku Materials,located in Pocatello,Idaho.
At the time this forecast was completed (August 2010),Hoku Materials planned to begin
operation in January 2011 and will reach full capacity by April 2011.The current sales and load
forecast assumes that Hoku Materials will consume 74 aMW of energy each year and have a
peak demand of 82 MW (each measure excluding line losses)once continuous operation is
reached in 2013.
•The load forecast used for the 2011 IRP reflects a recovery in the service area economy
following a severe recession in 2008 and 2009,as well as a much smaller impact of carbon
regulation on future energy rates charged to Idaho Power retail customers.Both factors resulted
in a higher long-term load forecast than was used in the 2009 IRP.The collapse in the housing
sector in 2008 and 2009 dramatically slowed the growth in the number of new households and
residential customers being added to Idaho Power’s service area.In addition,the number of
commercial customers being added also slowed dramatically as a result of the economic
downturn.However,by 2012,residential and commercial customer growth is expected to
recover;and by 2015,customer additions are forecast to approach the growth that occurred prior
to the housing bubble (2000—2004).
•In this year’s forecast,an additional customer referred to in this document as “Special”was
included in the Additional Firm Load category,even though a long-term contract had not yet
been fully executed.At the time this forecast was prepared (August 2010),several interested
parties had taken significant steps toward the ultimate development and location of their
businesses within Idaho Power’s service area.It was determined that the real possibility of the
new large load was significant enough that it would be imprudent of the company to ignore the
possible impact.The anticipated load of the new “Special”contract has been included in this
2011 Integrated Resource Plan Page 3
Appendix A—Sales and Load Forecast Idaho Power Company
forecast based on discussions with the interested parties.The existing special contracts and the
new “Special”contract together make up the Additional Firm Load category.
•There continues to be significant uncertainty associated with the growth of new industrial and
special contract customers and their potential impact on the load forecast.The forecast
uncertainty is associated with the increasing number of entities that have contacted Idaho Power
and expressed interest in locating their operations within Idaho Power’s service area and the
unknown magnitude of the energy and peak-demand requirements.The current sales and load
forecast reflects only those customers that have a very high probability ofrelocating to the
service area or have made financial commitments and whose facilities are actually being
constructed at this time.Therefore,the large numbers of businesses that have contacted
Idaho Power and shown interest,but have not made commitments,are not included in the current
sales and load forecast.
•In another improvement to this year’s forecast,Idaho Power used Itron’s residential Statistically
Adjusted End-Use (SAE)model to prepare the long-term residential sales forecast.Recently,
many utilities have adopted Itron’s SAE modeling approach to include greater end-use
information into the forecast process.
•Existing energy efficiency program performance is estimated and included in the sales and load
forecast base,lowering the energy and peak demand forecast.However,the impact of demand
response programs is accounted for in the IRP load and resource balance.The amount of
committed and implemented DSM programs for each month of the planning period is shown in
the IRP load and resource balance in Appendix C—TechnicalAppendix.
•A somewhat higher irrigation sales forecast is expected,compared to earlier forecasts (prior to
the 2009 IRP)due to a substantial increase in weather-adjusted irrigation sales in 2007 and 2008
(6%in 2007 and 8%in 2008).Higher farm commodity prices appear to be the primary reason
behind the irrigation sales increase.Farmers appear to have taken advantage of the commodities
market by planting all available acreage.In addition,the conversion of hand line to electrically
operated pivot irrigation systems may explain a part of the increased energy consumption.
In recent years,the increased labor costs associated with moving hand lines and increased
concerns for water conservation has triggered the substitution of labor with electrically
operated pivots.
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:
•This year’s peak forecast also reflects the increased expected peak demand of an additional
“Special”contract customer.The anticipated peak load of the new contract has been included in
this year’s forecast based on discussions with the interested parties.
•The 2011 IRP peak-demand forecast was adjusted downward to reflect the estimated impact of
energy efficiency DSM programs selected for implementation since 2001.Energy efficiency
programs are incorporated into the peak-demand forecast as the programs are committed
and implemented.
•The 2011 LRP peak demand forecast model does not consider or adjust for the impact of demand
response programs.The demand response programs are accounted for in the IRP load and
resource balance as a reduction in peak demand.
Page 4 2011 Integrated Resource Plan
Idaho Power Company Appendix A—Sales and Load Forecast
•The peak model allows peaks to be calculated at the 50th,90th,and 95th percentiles ofpeak day
temperatures for each month of the year.
•Recent historical peak data is added to the peak model regressions.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.In addition,new system peaks were
reached in July 2007 and again in June 2008 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;therefore,the median temperature better reflects expected temperatures.
The weighted average peak day temperature drivers are calculated over the 1980—2009 time
period (the most recent 30 years).
2011 Integrated Resource Plan Page 5
Appendix A—Sales and Load Forecast Idaho Power Company
This page left blank intentionally.
Page 6 2011 Integrated Resource Plan
Idaho Power Company Appendix A—Sales and Load Forecast
OVERVIEW OF THE FORECAST
The sales and load forecast is constructed by developing a separate forecast for each individual 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.,(Micron Technology),Simplot Fertilizer
Company (Simplot Fertilizer),Idaho National Laboratory (INL),Hoku Materials,one additional
high-probability special contract customer (referred to as “Special”),and Raft River Rural Electric
Cooperative,Inc.(Raft River)—the electric distribution utility serving Idaho Power’s former customers
in Nevada.These six,special contract customers are combined into a single forecast category labeled
Additional Firm Load.In the 2009 IRP sales and load forecast,the “Special”contract load was
combined with the industrial sector (Schedule 19)load forecast.Given the magnitude of their expected
future load,the “Special”contract has now been combined with the other larger special contract
customers that have monthly metered demands greater than 20,000 kilowatts (kW).Lastly,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
they are billed,it is necessary to adjust these billed sales to the proper timeframe 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 2011 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 usage coincides with significant
irrigation demand.
Peak loads are forecast using 12 regression equations and are a function of average peak day
temperatures,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 LNL,Micron Technology,Simplot Fertilizer,Hoku Materials,Idaho Power’s
newest “Special”contract customer,and Raft River are forecast based on 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 demand for
2011 Integrated Resource Plan Page 7
Appendix A—Sales and Load Forecast Idaho Power Company
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 US Energy Information Administration (ETA)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 (201 1—2030)
(average annual percent change)
Nominal Real*
Electricity—201 I IRP—Carbon 2.6%0.9%
Electricity—2009 IRP—Carbon 5.1%3.2%
Natural Gas 2.5%0.8%
*adjusted for inflation
Figure 1 illustrates the average electricity price paid by Idaho Power’s residential customers over the
historical period 1970—2010 and over the forecast period 2011—2030.Both nominal and real prices are
shown.In the 2011 IRP carbon scenario,nominal electricity prices are expected to slowly climb to
nearly 13 cents per kilowatt-hour (kWh)by the end of the forecast period in 2030.Real electricity prices
(inflation adjusted)in the carbon scenario are expected to increase over the forecast period at an average
rate of 0.9 percent each year.In the 2009 IRP electricity price carbon scenario,nominal electricity prices
were assumed to climb to nearly 22 cents per kWh by 2030,and real electricity prices (inflation
adjusted)were expected to increase over the forecast period at an average rate of 3.2 percent each year.
The impact of the much higher electricity price forecast on the 2009 IRP load forecast was significant
and served 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 2009 TRP reflected the
fixed and variable costs of integrating the resources identified by the 2006 IRP preferred portfolio,
including the expected costs of carbon emissions.When compared to the electricity price forecast used
to prepare the 2011 LRP sales and load forecast,the 2009 IRP price forecast yielded significantly higher
future prices.The price forecast difference is primarily the result of differing carbon cost assumptions
between the two forecasts.The 2009 IRP retail electricity price forecast assumed a carbon tax scenario
(from the 2006 IRP),and the 2011 IRP electricity price forecast assumed a cap-and-trade carbon
scenario (from the 2009 IRP).Under the cap-and-trade carbon scenario,Idaho Power curtailed carbon
emissions from coal units to comply with target emissions.
Page 8 2011 Integrated Resource Plan
Idaho Power Company Appendix A—Sales and Load Forecast
24
22 22
20
18
16
14
12 13
10
8
6
4
2
0 ——__________________
Nominal Nominal—2009 IRP
Nominal—201 1 IRP •Real—2009 IRP Real—201 I IRP
Figure 1.Forecasted electricity prices
(cents per kWh)
Electricity prices for Idaho Power customers moved significantly higher 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.Over the
1990—2000 period,electricity prices rose only 8 percent overall,an annual average compound growth
rate of 0.8 percent each year.
Figure 2 illustrates the average natural gas price paid by Intermountain Gas Company’s residential
customers over the historical period 1970—2009,and forecast prices from 20 10—2030.Natural gas prices
remained stable and flat throughout the 1 990s before moving sharply higher in 2001.Since spiking in
2001,natural gas prices moved downward for a couple of years before again moving sharply upward in
2004,2005,and 2006.Natural gas prices moved downward in 2010,reflecting the collapse in natural
gas prices that began in 2009.After bottoming in 2010,nominal natural gas prices are expected to rise in
2011,plateau through 2014,and then slowly rise throughout the remainder of the forecast period.
Natural gas prices at the end of the forecast period are expected to be about 40 percent higher than 2009,
growing at an average rate of 2.5 percent per year over the forecast period (2011—2030).Real natural gas
prices (adjusted for inflation)are expected to increase over the same period at an average rate of 0.8
percent each year.
1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030
Real
2011 Integrated Resource Plan Page 9
Appendix A—Sales and Load Forecast Idaho Power Company
$1.80
$1.60
$1.40
$0.40
$0.20
$0.00
ii I
___
III’
_
1HiIIIIIIWHHIII
—I I I I 111111
1111111111 111111
-_AUU11I1llIH liii
1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030
Nominal Actual Nominal Forecast —Real
Figure 2.Forecasted 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 2011 IRP price forecast,the long-term growth rates of electricity and
natural gas prices are nearly identical.
Electric Vehicles
With the anticipated introduction of electric vehicles in December 2010 from General Motors and
Nissan,Idaho Power includes a forecast of the potential load impact associated with customer needs for
battery recharging.Without the benefit of actual consumer adoption data and clarity on charging
infrastructure composition,the forecast methodology relies on previous modeling efforts from EPRI’
and Oak Ridge National Laboratory2 drawing on their forecasts of the electric-vehicle market share and
charging usage and loads.The assumptions of these and other early forecasts were made without benefit
of empirical vehicle performance attributes,such as vehicle battery capacity,pricing,actual consumer
adoption behavior,and other salient marketing variables.Since these variables represent primary
economic determinants of electric-vehicle adoption,the early forecasts are subject to potentially high
degrees of revision.Other determinant variables,such as gasoline price,exhibit high degrees of
volatility that add to the wide range of potential adoption outcomes.
The Oak Ridge study assumed a 25 percent electric-vehicle share of new vehicle registrations by 2020
and thereafter held constant.The EPRI study relied on year 2050 share scenarios that ranged from
20 percent to 80 percent.Their medium range forecast for 2020 was approximately 35 percent.
After evaluating historical rates of adoption of new transportation technology,particularly those
associated with fuel-efficient diesel engine adoption in Europe,the Idaho Power model was based on a
Environmental Assessment of Plug-In Hybrid Electric Vehicles,July,2007.
2 Potential Impacts ofPlug-in Hybrid Electric Vehicles on Regional Power Generation,January,2008.
2011 Integrated Resource Plan
\
Page 10
Idaho Power Company Appendix A—Sales and Load Forecast
40-percent share by 2050 with annual adoption growth rate associated with diesel-technology adoption.
The resulting Idaho Power forecast share of electric vehicles of new,light-duty vehicles registered in
Idaho Power’s service area is approximately 12 percent in 2020 and 26 percent in 2030.These rates
were applied to a forecast of new,light-duty vehicle registrations for Idaho Power’s service area using
base-case assumptions from Moody’s Analytics,Inc.
Idaho Power continues to capture consumer behavioral data and other salient market information
associated with electric-vehicle adoption for the purposes of improving the forecasting model in
future forecasts.
Figure 3 illustrates the increase in loads expected from the roll-out of electric vehicles over 2010—2030.
The impact on the load forecast is assumed to be relatively small—about 9 aMW in 2020,reaching
43 aMW at the end of the forecast period in 2030.The load impacts were allocated to the residential and
commercial sales forecasts using an 80/20 split,the residential sector representing the greatest impact.
50
40
I
10
________________
-4 IJ--’-
0 —-—--—-—-—
—___4__________——
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Commercial Residentia’
Figure 3.Electric vehicles
(aMW)
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,
Inc.,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 that 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.
2011 Integrated Resource Plan Page 11
Appendix A—Sales and Load Forecast Idaho Power Company
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 over the 1980—2009
time period (the most recent 30 years)was 1,036.The 70th percentile HDD is 1,074 and would be
exceeded in three-out-of-ten years.The 90th percentile HDD is 1,291 and would be exceeded in
one-out-of-ten years.The lOOrn 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 70tl 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 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 careful examination
of load variability and how it may impact future resource requirements.It is important to understand that
the probabilities associated with these forecasts apply to any given month.To assume that 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 9O percentile forecasts.
Table 2 summarizes the load scenarios prepared for the 2011 IRP.Three average load scenarios were
prepared based on a statistical analysis ofthe historical monthly weather variables listed.The probability
associated with each individual average load scenario is also indicated in the table.In addition,
three peak-demand scenarios were prepared based on a statistical analysis ofhistorical peak day average
temperatures.The probability associated with each individual peak-demand scenario is also indicated in
Table 2.
Table 2.Average load and peak-demand forecast scenarios
Probability
Weather Probability of Exceeding Weather DriverScenario
Forecasts of Average Load
90th Percentile 90%1-in-lO years HDD,CDD,ODD,Precipitation
70th Percentile 70%3-in-lO years HDD,CDD,GDD,Precipitation
Expected Case 50%i-in-2 years HDD,CDD,GDD,Precipitation
Forecasts of Peak Demand
95th Percentile 95%i-in-20 years Peak Day Temperatures
90th Percentile 90%1 -in-i 0 years Peak Day Temperatures
50th Percentile 50%1 -in-2 years Peak Day Temperatures
The analysis ofresource requirements is based on the 70th percentile average load forecast coupled with
the 95’’percentile peak-demand forecast to provide a more adverse representation of 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.
Page 12 2011 Integrated Resource Plan
Idaho Power Company Appendix A—Sales and Load Forecast
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 consideration and integration of existing energy efficiency
DSM program effects as a reduction to the average load forecast.fri addition,retail electricity prices also
serve to 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 ofpossible load growths for the 20 11—2030 planning period due to variable economic and
demographic conditions.The high economic growth and low economic growth scenarios were prepared
based on statistical analysis to empirically reflect 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 (1985—2009).
The estimated probabilities for the three different load scenarios are reported in Table 2.The probability
estimates are calculated using the annual growth rates in weather-adjusted system sales (excluding
Astaris)observed between 1985 and 2009.The standard deviation observed during the historical time
period is used to estimate the dispersion around the expected-case scenario.The probability estimates
assume that the expected forecast is the median growth path,i.e.,there is a 50-percent probability that
the actual growth rate will be less than the expected-case growth rate,and a 50-percent chance that the
actual growth rate will be greater than the expected-case growth rate.In addition,the probability
estimates assume that the variation in growth rates will be equivalent to the variation in growth rates
observed over the past 25 years (1985—2009).The high-and low-case load forecasts also reflect the
consideration and integration of existing energy efficiency DSM program effects as a reduction to the
average load 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 that
the actual growth rate will exceed the growth rate projected in the high scenario,and conversely,there is
a 10-percent chance that the actual growth rate would fall below that of the low scenario.In other words,
over a 20-year time 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 that 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,one-year,five-year,and 10-year time periods are also shown in Table 3.
2011 Integrated Resource Plan Page 13
Appendix A—Sales and Load Forecast Idaho Power Company
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%
System load includes the sum of residential,commercial,industrial,irrigation,special contracts
(including Astaris,historically),and Raft River.Idaho Power system load projections are reported in
Table 4 and pictured in Figure 4.The expected-case system load forecast growth rate averages
1.4 percent per year over the 20 years of the planning period.The low scenario projects that system load
will increase at an average rate of 1.0 percent per year throughout the forecast period.The high scenario
projects load growth of 1.8 percent per year.Idaho Power has experienced both the high-and
low-growth rates in the past.These scenario forecasts provide a range ofprojected growth rates that
cover approximately 80 percent of the probable outcomes as measured by Idaho Power’s
historical experience.
Table 4.System load growth
(aMW)
Annual Growth Rate
Growth 2011 2015 2020 2030 2011—2030
Low 1,793 1,894 1,970 2,158 1.0%
Expected 1,819 1,970 2,090 2,362 1.4%
High 1,878 2,094 2,271 2,642 1.8%
Page 14 2011 Integrated Resource Plan
Idaho Power Company Appendix A—Sales and Load Forecast
800
2010 2015 2020 2025 2030
WeatherAdjusted less Astaris —WeatherAdjusted
Figure 4.Forecasted system load
(aMW)
Expected —70th Percentile High —Low
2,800
2,600
2,400
2,200
2,000
1,800
1,600
1,400
1,200
1,000
1980 1985 1990 1995 2000
2011 Integrated Resource Plan Page 15
Appendix A—Sales and Load Forecast Idaho Power Company
This page left blank intentionally.
Page 16 2011 Integrated Resource Plan
Idaho Power Company Appendix A—Sales and Load Forecast
RESIDENTIAL
The expected-case residential load is forecast to increase from 595 aMW in 2011 to 786 aMW in 2030,
an average annual compound growth rate of 1.5 percent.In the percentile scenario,residential load
is forecast to increase from 611 aMV/in 2011 to 810 aMW in 2030,matching the expected-case
residential growth rate.The residential load forecasts are reported in Table 5 and shown graphically in
Figure 5.
Table 5.Residential load growth
(aM4,9
Annual Growth RateGrowth20112015202020302011—2030
901h Percentile 646 681 744 860 1.5%
701h Percentile 611 644 702 810 1.5%
Expected Case 595 626 682 786 1.5%
1,000
900
500 —rn-w—
200
100
0 IllIllIllIll 111111 111111 111111 liii II 1111111111111 liii
1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030
—WeatherAdjusted Expected Case —70th Percentile 90th Percentile
Figure 5.Forecasted residential load
(aMW)
Sales to residential customers made up 33 percent of Idaho Power’s system sales in 1980 and
37 percent of system sales in 2010.The residential customer proportion of system sales is forecast to be
approximately 36 percent in 2030.There were 408,754 residential customers as of December 2010.
The number of residential customers is projected to increase to approximately 536,000 by
December 2030.The relative customer proportions of Idaho Power’s total electricity sales are shown
in Figure 16.
The average sales per residential customer were nearly 13,000 kWh in 1975.Average sales increased to
over 14,800 kWh per residential customer in 1979 before declining to 13,150 kWh in 2001.In 2002 and
2003,residential-use-per-customer dropped dramatically—over 500 kWh per customer from 200 1—
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
2011 Integrated Resource Plan Page 17
Appendix A—Sales and Load Forecast Idaho Power Company
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 rise to approximately 12,900 kWh per year in 2030.Average annual sales per residential
customer are shown in Figure 6.
16,000
15,000
14,000
13,000
12,000
11,000
10,000
j
________
1[fliTliIIII[W nil
III I liii
Jffl1llllfiIth
1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030
Figure 6.Forecasted 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,Inc.,July 2010 forecast of county housing stock and demographic data.The residential-
customer forecast for 2011—2030 shows an average annual growth rate of 1.4 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,Inc.,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 forecasted DSM,by the residential-customer forecast.
2011 Integrated Resource Plan
I
Page 18
Idaho Power Company Appendix A—Sales and Load Forecast
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,commercial load is projected to increase from 439 aMW in 2011 to
561 aMW in 2030.The average annual compound-growth rate of commercial load is 1.3 percent during
the forecast period.As summarized in Table 6,the commercial load in the 70th percentile scenario is
projected to increase from 443 aMW in 2011 to 568 aMW in 2030.The commercial load forecasts are
illustrated in Figure 7.
Table 6.Commercial load growth
(aMW)
Annual Growth RateGrowth20112015202020302011—2030
90th Percentile 453 479 504 583 1.3%
70th Percentile 443 468 492 568 1.3%
Expected Case 439 463 486 561 1.3%
700
600
500
400
300
200
100
0 I-T I II II II I II I I II III III IJjII IIll IIIII IlII III
1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030
—WeatherAdjusted Expected Case —70th Percentile 90th Percentile
Figure 7.Forecasted commercial load
(aMW)
As of December 2010,Idaho Power had 64,647 commercial customers.The number of commercial
customers is expected to increase at an average annual growth rate of 2 percent,reaching
94,600 customers by 2030.Commercial customers consumed nearly 17 percent of Idaho Power system
sales in 1980 and nearly 28 percent of system sales in 2010.The commercial customer proportion of
system sales is projected to decline to 26 percent of system sales by 2030.The relative customer
proportions of Idaho Power’s total electricity sales are shown in Figure 16.
2011 Integrated Resource Plan Page 19
Appendix A—Sales and Load Forecast Idaho Power Company
The average consumption per commercial customer increased to a record 67,500 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 over
the time period 201 0—20 11,commercial-use-per-customer is projected to continue its downward trend.
The primary reasons for the 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 52,400 kWh per customer in 2030.Average annual use per
commercial customer is shown in Figure 8.
70,000
65,000
60,000
55,000
50,000
45,000
40,000
Figure 8.Forecasted 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,Inc.,July 2010 economic forecast
of county housing stock and demographic data.The commercial-customer forecast for 20 11—2030
shows an average annual growth rate of 2 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 Moody’s
Analytics,Inc.,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 forecasted DSM,by
the commercial-customer forecast.
1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030
Page 20 2011 Integrated Resource Plan
Idaho Power Company Appendix A—Sales and Load Forecast
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 forecasted period,the expected-case irrigation load is forecast to slowly rise from
197 aMW in 2011 to 207 aMW in 2030,an average annual compound growth rate of 0.3 percent.
The expected-case,70th percentile,and 9O”percentile scenarios forecast slow growth in irrigation load
over the 2011—2030 time period.In the 70th percentile scenario,irrigation load is projected to be
213 aMW in 2011 and 223 aMW in 2030.The individual irrigation load forecasts are reported in
Table 7 and shown in Figure 9.The figure illustrates the poorer economic conditions and the dramatic
reduction in land being put into production that was experienced by the agricultural economy in
the mid-1980s.
Table 7.Irrigation load growth
(aMW)
Annual Growth Rate
Growth 2011 2015 2020 2030 2011—2030
90th Percentile 232 234 237 242 0.2%
70th Percentile 213 215 217 223 0.2%
Expected Case 197 199 202 207 0.3%
300
275
250
225
200
175
150
125
100
1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030
Weather Adjusted Expected Case —70th Percentile 90th Percentile
Figure 9.Forecasted irrigation load
(aMV,9
It is important to understand the annual average-load figures reported in Table 7 and graphed in Figure 9
are calculated using the 8,760 hours of 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
2011 Integrated Resource Plan Page 21
Appendix A—Sales and Load Forecast Idaho Power Company
of the annual energy is billed in just two months,July and August.During the summer,hourly irrigation
loads can exceed 900 MW.In a normal July,irrigation pumping accounts for roughly 25 percent of the
energy consumed during the hour of the annual system peak and 30 percent of the energy consumed
during the July calendar-month for general business sales.Note that it is the monthly forecast load
figures that are being evaluated for resource planning purposes,not the annual average loads.
The 2011 irrigation sales forecast model considers several factors affecting electricity sales to the
irrigation class,including temperature,precipitation,spring rainfall,Moody ‘s Gross Produce:Farms,
for Idaho,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 consumption of electricity 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 1980.
Irrigation sales reached a maximum proportion of 20 percent of Idaho Power system sales in 1977.
In 2010,the irrigation proportion of system sales was 13 percent due to the much higher relative growth
in other customer classes.By 2030,irrigation customers are projected to consume less than 10 percent of
Idaho Power system sales.The irrigation customer load proportion is shown in Figure 16.
In 1980,Idaho Power had about 10,850 active irrigation accounts.By 2010,the number of active
irrigation accounts had increased to 17,846 and is projected to be about 23,500 irrigation accounts at the
end of the planning period in 2030.
Since 1988,Idaho Power has experienced some growth in the number of imgation 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 for these customers is
substantially less than the average existing Idaho Power irrigation customer.This is due to the fact that
water for furrow irrigation is gravity-drawn from canals and not pumped from deep,groundwater wells.
In 2007 and 2008,irrigation sales (weather-adjusted)increased by 8 percent and 6 percent,respectively,
over each prior year.The increase can be explained,in part,by the gradual increase in the planting of
more water-intensive crops,such as alfalfa and corn,to meet the higher demand for feed associated with
the growing dairy industry in Idaho.Also,2008 saw unprecedented crop prices for almost all crops,
causing customers to irrigate all of the acreage that was available in 2008.
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 individual 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 each year.
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
ofthese issues,irrigation sales may be impacted.
Page 22 2011 Integrated Resource Plan
Idaho Power Company Appendix A—Sales and Load Forecast
INDUSTRIAL
The industrial category is made up of Idaho Power’s Large Power Service (Schedule 19)customers with
monthly metered demands between 1,000 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 2010,the number of industrial customers had risen to 121,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 262 aMW in 2011 to 359 aMW in 2030,
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 and 90th percentile scenarios are identical to the
expected-case industrial load scenario.The industrial load forecast is pictured in Figure 10.
Table 8.Industrial load growth
(aM¼’9
Annual Growth RateGrowth20112015202020302011—2030
Expected Case 262 283 302 359 1.7%
450
400
350
300
250
200
150
100
50
0
1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030
—Actual
Figure 10.Forecasted industrial load
(aMW)
Expected Case
The industrial energy forecast is based on the most recent (July 2010)national,state,MSA,and county
economic forecasts from Moody’s Analytics,Inc.,and the resulting derived economic forecast for
Idaho Power’s service area.
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
2011 Integrated Resource Plan Page 23
Appendix A—Sales and Load Forecast Idaho Power Company
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
17 industry groups to determine the relationship between historical electricity sales and historical
employment,population,andlor 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 11 illustrates the 2010 industrial electricity consumption by industry group.By far the largest
share of electricity was consumed by the Food and Kindred Products sector (46 percent);followed by
Electronic/Electrical Equipment and Industrial/Commercial Machinery (7 percent);Educational
Services,‘Wholesale and Retail Trade,and Health Services (each representing 6 percent);
and Other Manufacturing (5 percent).As Figure 11 shows,several other industry groups make up the
remaining share of the 2010 industrial electricity consumption.
Electro nic/Electiical
Equipmentand
In d ustrial/Commercial
FoodandKindred ,“Machinery,6.8%
Products,45.5%
/Educational Services,
-0/—/6.0 o
.Wholese and Retail
Trade,5.9%
.—__.................Health Services,5.9%
Other Man ufacting,
Other Industry Groups,4.8%
17.2%
Stone,Clay,Glass,and
Concrete Products,4.3%
Figure 11.Industrial electricity consumption by industry group
(based on 2010 figures)
Executive,Legislative,
and General
Government,3.6%
Page 24 2011 Integrated Resource Plan
Idaho Power Company Appendix A—Sales and Load Forecast
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 of these individual large-power
customers.The contract and tariff schedule are then approved by the appropriate commission.A special
contract allows for customer-specific,cost-of-service analysis and consideration of 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,INL,and Hoku Materials.In addition,the company has a term
sales contract with Raft River.Raft River is not required to meet the 20-MW electric service minimum.
It is difficult to predict when a new special contract customer will begin taking service from
Idaho Power.However,because ofthe magnitude of their load and subsequent impact on system
resources,it is important to anticipate such load if a customer of that size is considered eminent.In this
year’s forecast,the company has included the anticipated load of an additional special contract customer
referred to as “Special”in the additional firm load category,even though a long-term special contract
had not yet been filly executed.At the time this forecast was prepared (August 2010),several interested
parties had taken significant steps toward the ultimate development and location of their businesses
within Idaho Power’s service area.It was determined that the real possibility of the new large load was
significant enough that it would be imprudent of the company to ignore the possible impact.
The anticipated load of the new “Special”contract has been included in this forecast based on
discussions with the interested parties.The existing special contract customers and the new “Special”
contract together make up the additional firm load category.
In the expected-case forecast,additional firm load is expected to increase from 165 aMW in 2011 to
243 aMW in 2030,an average growth rate of 2 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 12.
Table 9.Additional firm load growth
(aMW)
Annual Growth Rate
Growth 2011 2015 2020 2030 2011—2030
Expected Case 165 229 236 243 2%
2011 Integrated Resource Plan Page 25
Appendix A—Sales and Load Forecast Idaho Power Company
300
250
200
150
100
50
0
1975 1980 1985 2015 2020 2025 2030
—Actual Expected Case
Figure 12.Forecasted additional firm load
(aMW)
Micron Technology
Micron Technology is currently Idaho Power’s largest individual customer and employs approximately
5,000 workers in the Boise MSA.Electricity sales to Micron Technology moved considerably
downward in 2009 and 2010 as Micron phased out its 200-millimeter (mm)dynamic random access
memory (DRAM)operations at its Boise facility.The company continues to operate its 300-mm
research and development fabrication facility in Boise and perform a variety of other activities,
including product design and support,quality assurance,systems integration and related manufacturing,
corporate,and general services.Once establishing a new floor for energy consumption at the facility at
about a quarter less energy use than in recent years,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 United States.
The future electricity usage at the plant is expected to grow at a slow pace throughout the planning
period (2011—2030).The primary driver of long-term electricity sales growth at Simplot Fertilizer is
Moody’s Analytics,Inc.,forecast of gross product in the pesticide,fertilizer,and other agricultural
chemical manufacturing for the Pocatello MSA.
Idaho National Laboratory
The US Department of Energy (DOE)provided an energy-consumption and peak-demand forecast
through 2030 for the LNL.The forecast calls for loads to increase considerably through 2014,remain flat
for six years,and then slowly decline throughout the remainder of the forecast period.As of
October 1994,the 11L nuclear reactor no longer generates electricity,consequently,the amount of
electricity provided by Idaho Power increased considerably.
1990 1995 2000 2005 2010
Page 26 2011 Integrated Resource Plan
Idaho Power Company Appendix A—Sales and Load Forecast
Hoku Materials
The sales and load forecast reflects the increased expected demand for energy and peak capacity of
Idaho Power’s newest special contract customer,Hoku Materials,located in Pocatello,Idaho.At the
time this forecast was completed (August 2010),Hoku Materials was planning to begin operation in
January 2011 and reach full capacity by April 2011.The current sales and load forecast assumes that
Hoku Materials will consume 74 aMW of energy each year and have a peak demand of 82 MW
(each measure excluding line losses),once continuous operation is reached in 2013.
“Special”Contract
In this year’s forecast,an additional customer referred to in this document as “Special”was included in
the additional firm load category,even though a long-term contract had not yet been fully executed.
At the time this forecast was prepared (August 2010),several interested parties had taken significant
steps toward the ultimate development and location of their businesses within Idaho Power’s service
area.It was determined that the real possibility of the new large load was significant enough that it
would be imprudent of the company to ignore the possible impact.The anticipated load of the new
“Special”contract has been included in this forecast based on discussions with the interested parties.
The existing special contracts and the new “Special”contract together make up the additional firm
load category.
Raft River Rural Electric Cooperative
A term sales contract with Raft River was established as a full-requirements contract after being
approved by the Federal Energy Regulatory Commission (FERC)and the Public Utility Commission of
Nevada.Raft River is the electric distribution utility serving Idaho Power’s former customers in Nevada.
In April 2001,Idaho Power sold the transmission facilities and rights-of-way that serve about
1,250 customers in northern Nevada and 90 customers in southern Owyhee County to Raft River.
Raft River is located entirely within Idaho Power’s load control area.
The contract with Raft River expired on September 30,2010.However,Raft River renewed the
agreement for an additional one-year term,which would extend service until September 30,2011.
The load forecasts in the 2011 IRP assume that Idaho Power will continue to provide service to the
Raft River area through September 30,2011.
2011 Integrated Resource Plan Page 27
Appendix A—Sales and Load Forecast Idaho Power Company
This page left blank intentionally.
Page 28 2011 Integrated Resource Plan
Idaho Power Company Appendix A—Sales and Load Forecast
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 Raft River.
The all-time system summer peak demand was 3,214 MW,recorded on Monday,June 30,2008,
at 3:00 p.m.The previous year’s summer peak demand was 3,193 MW and occurred on Friday,
July 13,2007,at 4:00 p.m.The summer system peak load growth accelerated over the 10 years ending
in 2008 as a record number of residential and commercial customers were added to the system and air
conditioning became standard in nearly all new residential homes and new commercial buildings.
In the 90t1 percentile forecast,total system summer peak load is expected to increase from 3,494 MW in
2011 to 4,870 MW in the year 2030,an average growth rate of 1.8 percent per year over the planning
period (Table 10).In the 95th percentile forecast,total system summer peak load is expected to increase
from 3,515 MW in 2010 to 4,901 MW in the year 2030.The three scenarios of projected system summer
peak load are illustrated in Figure 13.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)
Annual Growth RateGrowth20112015202020302011—2030
95th Percentile 3515 3,854 4,190 4,901 1.8%
9othPercentile 3,494 3,831 4,164 4,870 1.8%
50th Percentile 3,334 3,657 3,973 4,643 1.8%
5,200
4,800
4,400
4,000
3,600
3,200
2,800
2,400
2,000
1,600
1,200
Actual less Astaris —Actual —50th Percentile —90th Percentile —95th Percentile
Figure 13.Forecasted system summer peak
(MW)
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 14,historical system winter peak load is much more variable than
-.
1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030
2011 Integrated Resource Plan Page 29
Appendix A—Sales and Load Forecast Idaho Power Company
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 ofthe
winter peak forecast lines in Figure 14 illustrates the higher variability associated with winter
peak-day temperatures.
In the 90th percentile forecast,total system winter peak load is expected to increase from 2,693 MW in
2011 to 3,336 MW in 2030,an average growth rate of 1.1 percent per year over the planning period
(Table 11).In the 95th percentile forecast,total system winter peak load is expected to increase from
2,815 MW in 2011 to 3,509 MW in 2030,an average growth rate of 1.2 percent per year over the
planning period (Table 11).The three scenarios of projected system winter peak load are illustrated in
Figure 14.
Table II.System winter peak load growth
(M
Annual Growth Rate
Growth 2011 2015 2020 2030 2011—2030
95th Percentile 2,815 2,948 3,121 3,509 1.2%
gothpercentile 2,693 2,815 2,976 3,336 1.1%
50th Percentile 2,384 2,478 2,604 2,896 1.0%
3,700
3,400
3,100
2,800
2,500
2,200
1,900
1,600
1,300
ActuaI less Astaris —Actual —50th Percentile —90th Percentile —95th Percentile
Figure 14.Forecasted system winter peak
(MW)
r
1,000
1975-76 1981-82 1987-88 1993-94 1999-00 2005-06 2011-12 2017-18 2023-24 2029-30
Page 30 2011 Integrated Resource Plan
Idaho Power Company Appendix A—Sales and Load Forecast
COMPANY SYSTEM LOAD
System load is the sum of the individual loads of residential,commercial,industrial,and irrigation
customers,as well as special contracts (including past sales to Astaris)and Raft River.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,Inc.,economic
forecast for the nation and 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 1.4 percent per
year over the 20 11—2030 time period.Company system load projections are reported in Table 12 and
shown in Figure 15.
In the expected-case forecast,company system load is expected to increase from 1,819 aMW in 2011 to
2,362 aMW in 2030.In the 70th percentile forecast,company system load is expected to increase from
1,860 aMW in 2011 to 2,414 aMW by 2030,an average growth rate of 1.4 percent per year over the
planning period (Table 12).
Table 12.System load growth
(aMV9
Annual Growth Rate
Growth 2011 2015 2020 2030 2011—2030
90t’Percentile 1,931 2,088 2,218 2,508 1.4%
70th Percentile 1,860 2,013 2,136 2,414 1.4%
Expected Case 1,819 1,970 2,090 2,362 1.4%
2,800
2,500 -
2,200
1,300
1,000
Figure 15.Forecasted system load
(aML49
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
1,900
1,600
700
1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030
WA less Astaris —Weather Adjusted —Expected Case —70th Percentile 90th Percentile
2011 Integrated Resource Plan Page 31
Appendix A—Sales and Load Forecast Idaho Power Company
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 excluding Astaris more accurately portrays the
underlying general business growth trend within the service area.
Page 32 2011 Integrated Resource Plan
Idaho Power Company Appendix A—Sales and Load Forecast
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.
2011 Integrated Resource Plan Page 33
Appendix A—Sales and Load Forecast Idaho Power Company
This page left blank intentionally.
Page 34 2011 Integrated Resource Plan
Idaho Power Company Appendix A—Sales and Load Forecast
TOTAL COMPANY LOAD
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
total 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 total company electricity sales by year is shown in Figure 16.Residential sales are
forecast to be over 32 percent higher in 2030,gaining nearly 1.7 million MWh over 2011.Commercial
sales are expected to be nearly 28 percent higher or nearly 1.1 million MWh above 2011 followed by
industrial (37 percent higher or nearly 0.8 million additional MWh)and irrigation (only 5 percent higher
in 2030 than 2011).Electricity sales to Astaris ended in April 2002.
20,000
18,000
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
U Residential
Figure 16.Composition of total company electricity sales
(thousands ofMWh)
The additional firm load category (which represents sales to Micron Technology,Simplot Fertilizer,
INL,Hoku Materials,Idaho Power’s newest “Special”contract customer,and Raft River)is forecast to
grow by 47 percent over the 20 11—2030 time period,largely due to the addition of Hoku Materials and
Idaho Power’s newest “Special”contract customer as special contract customers.
1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030
U Commercial lndustrial U Irrigation J Additional Firm Sales Astaris U Firm Off-System
2011 Integrated Resource Plan Page 35
Appendix A—Sales and Load Forecast Idaho Power Company
This page left blank intentionally.
Page 36 2011 Integrated Resource Plan
Idaho Power Company Appendix A—Sales and Load Forecast
DEMAND-SIDE MANAGEMENT
DSM consists of energy efficiency programs that reduce customer energy use year-round and demand
response programs that are targeted at reducing load during specific periods of high demand.The impact
of energy efficiency programs are considered in the 2011 IRP Appendix A—Sales andLoad Forecast;
however,demand response programs are accounted for in the 2011 IRP load and resource balance and
not in the load forecast.The sales and load forecast,adjusted for existing and committed energy
efficiency programs,serves as the basis for establishing the baseline forecast for surpluses and deficits
which were used to develop portfolios for the 2011 IRP.
Energy Efficiency Programs
The 2011 IRP Appendix A—Sales andLoad Forecast follows the methodology established in an Itron
white paper3,“Incorporating DSM into the Load Forecast”.The authors discussed methods for adjusting
load forecasts to account for DSM programs.According to Itron,there are several potential econometric
frameworks that can be applied to account for DSM in the forecast period.The methods are designed to
adjust the load forecast by accounting for the amount and continuing momentum of the historic DSM
contained in the load forecast model.
The “DSM trend”method was chosen as the preferred method to incorporate DSM into the load
forecasts for the commercial,industrial,and irrigation sectors.The alternative methods make explicit
efforts to adjust DSM out of the history and out of the forecast.The DSM trend takes a different
approach by recognizing that historical DSM and DSM trends are embedded in the actual sales data.
Forecasting models built on these data implicitly assume that the levels and trends for DSM savings in
the history continue into the forecast at approximately the same rate.As a result,the forecast needs to be
adjusted only if DSM impacts are expected to be greater or less than the historical trends.
In the final step of the D SM trend method,the forecast is adjusted if the cumulative impacts of past and
future programs are expected to accelerate or decelerate relative to the DSM trend line.In this method,
the forecast is adjusted up or down by the difference between the DSM trend line and the cumulative
impact of past and future programs.
If the total cumulative impact ofpast and future programs is expected to fall short of the historical trend,
then the energy forecast should be adjusted upward by the amount of the deceleration below the DSM
trend line.
In another improvement to this year’s forecast,Idaho Power used Itron’s residential SAE model to
prepare the long-term residential sales forecast.Recently,many utilities have adopted Itron’s SAE
modeling approach to include greater end-use information into the forecast process.When applying the
SAE framework,DSM activity is naturally incorporated in the efficiency assumptions and the
calibration to historic sales data.Efficiency assumptions incorporate national-level DSM impacts.
Calibration incorporates specific utility DSM impacts.Therefore,additional adjustments to the
residential energy forecast for existing DSM programs were not made.
When using an econometric or SAE model,historical DSM investments influence the historical sales
data,the forecast model parameters,and the resulting sales projections.As DSM investment increases,
Stuart McMenamin and Mark Quan.“Incorporating DSM into the Load Forecast.”Itron,
https://www.itron.cornlna/PublishedContent/Incorporating%2ODSM%20into%2othe%2OLoad%2OForecast.pdf
(accessed February 3,2011).
2011 Integrated Resource Plan Page 37
Appendix A—Sales and Load Forecast Idaho Power Company
forecasters need to adjust their sales forecasts to account for this acceleration relative to the historic
DSM implicitly included in an unadjusted forecast.
The forecast resulting from the adjusted history is designed to reflect sales without the impact of energy
efficiency programs.The results from the regression models are subsequently adjusted downward to
account for future energy efficiency program performance.
Energy savings from energy efficiency programs are typically measured and reported at the point of
delivery (customers’meter).Therefore,energy efficiency savings are increased by the amount of energy
lost in transmitting the electricity from the generation source to the customers’meter.
Because the sales and load forecast is prepared before new energy efficiency programs are determined,
new energy efficiency programs are not included in the forecast.The impact of the new programs is
accounted for in the IRP load and resource balance prior to determining the need for additional
supply-side resources.The forecast performance of both 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 Programs
Prior to the 2009 IRP,demand response program performance was accounted for in the sales and load
forecast.Beginning with the 2009 IRP,demand response programs are 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 2011 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 due to energy efficiency programs that is 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 2010 Annual Report.
Page 38 2011 Integrated Resource Plan
Idaho Power Company Appendix Al.Historical and Projected Sales and Load
Appendix Al.Historical and Projected Sales and Load
Residential Load
Historical Residential Sales and Load,1970—2010
(weather-adjusted)
Percent kWh per Billed Sales Percent Average Load
Year Customers Change Customer (thousands of MWh)Change (MW)
1970 132,135 9,944 1,314 151
1971 138,071 4.5%10,392 1,435 9.2%165
1972 145,208 5.2%10,838 1,574 9.7%182
1973 152,957 5.3%11,501 1,759 11.8%202
1974 160,151 4.7%12099 1,938 10.1%224
1975 167,622 4.7%12871 2,158 11.3%249
1976 175,720 4.8%13,544 2,380 10.3%273
1977 184,561 5.0%13,594 2,509 5.4%288
1978 194,650 5.5%14,427 2,808 11.9%325
1979 202,982 4.3%14,821 3,008 7.1%343
1980 209,629 3.3%14,741 3,090 2.7%352
1981 213,579 1.9%14,416 3,079 -0.4%352
1982 216,696 1.5%14,627 3,170 2.9%362
1983 219,849 1.5%14,430 3,172 0.1%366
1984 222,695 1.3%14,438 3,215 1.4%364
1985 225,185 1.1%14,375 3,237 0.7%371
1986 227,081 0.8%14,244 3,234 -0.1%368
1987 228,868 0.8%14037 3,213 -0.7%365
1988 230,771 0.8%14,282 3,296 2.6%376
1989 233,370 1.1%14,463 3,375 2.4%386
1990 238,117 2.0%14,236 3,390 0.4%393
1991 243,207 2.1%14,654 3,564 5.1%404
1992 249,767 2.7%14,062 3,512 -1.5%405
1993 258,271 3.4%14,392 3,717 5.8%419
1994 267,854 3.7%13,957 3,738 0.6%433
1995 277,131 3.5%14,067 3,898 4.3%440
1996 286,227 3.3%13,759 3,938 1.0%456
1997 294,674 3.0%13,692 4,035 2.4%464
1998 303,300 2.9%13,727 4,164 3.2%475
1999 312,901 3.2%13,616 4,260 2.3%488
2000 322,402 3.0%13,409 4,323 1.5%500
2001 331,009 2.7%13,156 4,355 0.7%476
2002 339,764 2.6%12,616 4,286 -1.6%487
2003 349,219 2.8%12,639 4,414 3.0%507
2004 360,462 3.2%12,689 4,574 3.6%525
2005 373,602 3.6%12,687 4,740 3.6%543
2006 387,707 3.8%12,872 4,991 5.3%568
2007 397,286 2.5%12,940 5,141 3.0%585
2008 402,520 1.3%12,858 5,176 0.7%594
2009 405,144 0.7%12,696 5,144 -0.6%585
2010 407,551 0.6%12,441 5,070 -1.4%582
2011 Integrated Resource Plan Page 39
Appendix Al.Historical and Projected Sales and Load Idaho Power Company
Residential Load
Projected Residential Sales and Load,2011—2030
Percent kWh per Billed Sales Percent Average Load
Year Customers Change Customer (thousands of MWh)Change (MW)
2011 411,162 0.9%12,677 5,212 2.8%595
2012 415,787 1.1%12,514 5,203 -0.2%594
2013 423,098 1.8%12,350 5,225 0.4%598
2014 432,043 2.1%12,425 5,368 2.7%614
2015 440,364 1.9%12,441 5,478 2.1%626
2016 447,754 1.7%12,425 5,563 1.6%636
2017 454,724 1.6%12,468 5,669 1.9%648
2018 461,592 1.5%12,473 5,757 1.6%658
2019 468,394 1.5%12,530 5,869 1.9%671
2020 475,070 1.4%12,568 5,971 1.7%682
2021 481,514 1.4%12,578 6,056 1.4%692
2022 487,734 1.3%12,627 6,159 1.7%704
2023 493,690 1.2%12,703 6,271 1.8%717
2024 499,477 1.2%12,737 6,362 1.4%727
2025 505,167 1.1%12,722 6,427 1.0%734
2026 510,811 1.1%12,745 6,510 1.3%743
2027 516,404 1.1%12,691 6,554 0.7%749
2028 521,918 1.1%12,851 6,707 2.3%766
2029 527,380 1.0%12,849 6,776 1.0%774
2030 532,835 1.0%12,908 6,878 1.5%786
Page 40 2011 Integrated Resource Plan
Idaho Power Company Appendix Al.Historical and Projected Sales and Load
Commercial Load
Historical Commercial Sales and Load,1970—2010
(weather-adjusted)
Percent kWh per Billed Sales Percent Average Load
Year Customers Change Customer (thousands of MWh)Change (MW)
1970 21,375 42,773 914 105
1971 22,077 3.3%45,388 1,002 9.6%115
1972 22,585 2.3%46,142 1,042 4.0%120
1973 23,286 3.1%48,144 1,121 7.6%128
1974 24,096 3.5%49,027 1,181 5.4%136
1975 25,045 3.9%51,218 1,283 8.6%147
1976 26,034 3.9%52,512 1,367 6.6%157
1977 27,112 4.1%52,414 1,421 3.9%162
1978 27,831 2.7%52,474 1,460 2.8%169
1979 28,087 0.9%56,389 1,584 8.4%180
1980 28,797 2.5%54,141 1,559 -1.6%178
1981 29,567 2.7%54,282 1,605 2.9%184
1982 30,167 2.0%54,126 1,633 1.7%186
1983 30,776 2.0%52,684 1,621 -0.7%186
1984 31,554 2.5%53,410 1,685 3.9%191
1985 32,417 2.7%54,076 1,753 4.0%201
1986 33,208 2.4%53,747 1,785 1.8%203
1987 33,975 2.3%53,312 1,811 1.5%206
1988 34,723 2.2%54,432 1,890 4.4%216
1989 35,638 2.6%55,285 1,970 4.2%226
1990 36,785 3.2%55,761 2,051 4.1%236
1991 37,922 3.1%56,076 2,127 3.7%243
1992 39,022 2.9%56,359 2,199 3.4%253
1993 40,047 2.6%57,970 2,321 5.6%263
1994 41,629 4.0%58,246 2,425 4.4%280
1995 43,165 3.7%58,555 2,528 4.2%287
1996 44,995 4.2%61,960 2,788 10.3%322
1997 46,819 4.1%62,038 2,905 4.2%333
1998 48,404 3.4%62,713 3,036 4.5%347
1999 49,430 2.1%64,186 3,173 4.5%363
2000 50,117 1.4%66,043 3,310 4.3%383
2001 51,501 2.8%67,454 3,474 5.0%384
2002 52,915 2.7%64,719 3,425 -1.4%390
2003 54,194 2.4%64,320 3,486 1.8%399
2004 55,577 2.6%63,898 3,551 1.9%407
2005 57,145 2.8%63,527 3,630 2.2%415
2006 59,050 3.3%63,487 3,749 3.3%427
2007 61,640 4.4%63,330 3,904 4.1%445
2008 63,492 3.0%62,249 3,952 1.2%451
2009 64,151 1.0%59,635 3,826 -3.2%437
2010 64,421 0.4%58,851 3,791 -0.9%434
2011 Integrated Resource Plan Page 41
Appendix Al.Historical and Projected Sales and Load Idaho Power Company
Commercial Load
Projected Commercial Sales and Load,2011—2030
Percent kWh per Billed Sales Percent Average Load
Year Customers Change Customer (thousands of MWh)Change (MW)
2011 64,995 0.9%59,059 3,839 1.2%439
2012 66,265 2.0%58,734 3,892 1.4%445
2013 67,892 2.5%58,122 3,946 1.4%451
2014 69,600 2.5%57,471 4,000 1.4%457
2015 71,252 2.4%56,873 4,052 1.3%463
2016 72,840 2.2%56,204 4,094 1.0%468
2017 74,398 2.1%55,579 4,135 1.0%472
2018 75,950 2.1%54,977 4,176 1.0%477
2019 77,497 2.0%54,399 4,216 1.0%482
2020 79,031 2.0%53,841 4255 0.9%486
2021 80,551 1.9%53,342 4,297 1.0%491
2022 82,058 1.9%52,929 4,343 1.1%496
2023 83,549 1.8%52,592 4,394 1.2%502
2024 85,030 1.8%52,307 4,448 1.2%508
2025 86,505 1.7%52,116 4,508 1.4%515
2026 87,976 1.7%52,022 4,577 1.5%523
2027 89,445 1.7%51,979 4,649 1.6%531
2028 90,906 1.6%52,057 4,732 1.8%541
2029 92,365 1.6%52,166 4,818 1.8%550
2030 93,823 1.6%52,363 4,913 2.0%561
Page 42 2011 Integrated Resource Plan
Idaho Power Company Appendix Al.Historical and Projected Sales and Load
Irrigation Load
Historical Irrigation Sales and Load,1970—2010
(weather-adjusted)
Percent kWh per Billed Sales Percent Average Load
Year Customers Change Customer (thousands of MWh)Change (MW)
1970 7,319 126,039 922 105
1971 7,518 2.7%136,020 1,023 10.9%117
1972 7,815 4.0%131,163 1,025 0.2%117
1973 8,341 6.7%140,226 1,170 14.1%134
1974 8,971 7.6%147,179 1,320 12.9%151
1975 9,480 5.7%154,226 1,462 10.7%167
1976 9,936 4.8%152,340 1,514 3.5%172
1977 10,238 3.0%160,870 1647 8.8%188
1978 10,476 2.3%152,800 1,601 -2.8%183
1979 10,711 2.2%159,986 1,714 7.1%195
1980 10,854 1.3%154,900 1,681 -1.9%191
1981 11,248 3.6%165,138 1,857 10.5%212
1982 11,312 0.6%150,370 1,701 -8.4%194
1983 11,133 -1.6%143,424 1,597 -6.1%182
1984 11,375 2.2%131,427 1,495 -6.4%170
1985 11,576 1.8%133,730 1,548 3.6%177
1986 11,308 -2.3%134,686 1,523 -1.6%174
1987 11,254 -0.5%127,375 1,433 -5.9%164
1988 11,378 1.1%136,257 1,550 8.2%176
1989 11,957 5.1%137,704 1,647 6.2%188
1990 12,340 3.2%144,106 1,778 8.0%203
1991 12,484 1.2%133,777 1,670 -6.1%191
1992 12,809 2.6%139,469 1,786 7.0%203
1993 13,078 2.1%126,585 1,655 -7.3%189
1994 13,559 3.7%128,848 1,747 5.5%199
1995 13,679 0.9%125,761 1,720 -1.5%196
1996 14,074 2.9%123,537 1,739 1.1%198
1997 14,383 2.2%114,002 1,640 -5.7%187
1998 14,695 2.2%112,933 1,660 1.2%189
1999 14,912 1.5%117,103 1,746 5.2%199
2000 15,253 2.3%125,903 1,920 10.0%219
2001 15,522 1.8%115,103 1,787 -7.0%204
2002 15,840 2.0%109,768 1,739 -2.7%198
2003 16,020 1.1%108,979 1,746 0.4%199
2004 16,297 1.7%106,547 1,736 -0.5%198
2005 16,936 3.9%98,843 1,674 -3.6%191
2006 17,062 0.7%96,848 1,652 -1.3%189
2007 17,001 -0.4%104,905 1,783 7.9%204
2008 17,428 2.5%108,350 1,888 5.9%215
2009 17,708 1.6%100,186 1,774 -6.0%203
2010 17,846 0.8%99,148 1,769 -0.3%202
2011 Integrated Resource Plan Page 43
Appendix Al.Historical and Projected Sales and Load Idaho Power Company
Irrigation Load
Projected Irrigation Sales and Load,2011—2030
Percent kWh per Billed Sales Percent Average Load
Year Customers Change Customer (thousands of MWh)Change (MW)
2011 18,264 2.3%94,526 1,726 -2.4%197
2012 18,541 1.5%93,518 1,734 0.4%197
2013 18,821 1.5%91,968 1,731 -0.2%198
2014 19,101 1.5%90,686 1,732 0.1%198
2015 19,379 1.5%90,049 1,745 0.7%199
2016 19,655 1.4%89,212 1,753 0.5%200
2017 19,932 1.4%88,237 1,759 0.3%201
2018 20,212 1.4%87,324 1,765 0.4%201
2019 20,487 1.4%86,337 1,769 0.2%202
2020 20767 1.4%85,426 1,774 0.3%202
2021 21,045 1.3%84,531 1,779 0.3%203
2022 21,323 1.3%83,591 1,782 0.2%203
2023 21601 1.3%82,745 1,787 0.3%204
2024 21,878 1.3%81,991 1,794 0.4%204
2025 22,157 1.3%81,160 1,798 0.2%205
2026 22,437 1.3%80,269 1,801 0.2%206
2027 22,712 1.2%79,463 1,805 0.2%206
2028 22,988 1.2%78,494 1,804 0.0%205
2029 23,268 1.2%77,943 1,814 0.5%207
2030 23,547 1.2%77,079 1,815 0.1%207
Page 44 2011 Integrated Resource Plan
Idaho Power Company Appendix Al.Historical and Projected Sales and Load
Industrial Load
Historical Industrial Sales and Load,1970—2010
(weather-adjusted)
Percent kWh per Billed Sales Percent Average Load
Year Customers Change Customer (thousands of MWh)Change (MW)
1970 49 9,173,784 445 52
1971 50 3.3%10,474,941 525 17.9%60
1972 56 12.1%10,944,714 615 17.2%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%18,310,726 2,220 -0.2%254
2011 Integrated Resource Plan Page 45
Appendix Al.Historical and Projected Sales and Load Idaho Power Company
Industrial Load
Projected Industrial Sales and Load,2011—2030
Percent kWh per Billed Sales Percent Average Load
Year Customers Change Customer (thousands of MWh)Change (MW)
2011 121 -0.2%18,958,898 2,294 3.3%262
2012 125 3.3%18,768,661 2,346 2.3%268
2013 125 0.0%19,133,471 2,392 1.9%273
2014 126 0.8%19,320,558 2,434 1.8%278
2015 128 1.6%19,318,966 2,473 1.6%283
2016 131 2.3%19,155,425 2,509 1.5%286
2017 134 2.3%18,997,015 2,546 1.4%291
2018 134 0.0%19,256,620 2,580 1.4%295
2019 136 1.5%19,239,155 2,617 1.4%299
2020 139 2.2%19,087,337 2,653 1.4%302
2021 140 0.7%19,218,638 2,691 1.4%308
2022 142 1.4%19,241,280 2,732 1.5%312
2023 142 0.0%19,514,996 2,771 1.4%317
2024 145 2.1%19,391,910 2,812 1.5%321
2025 147 1.4%19,454,919 2,860 1.7%327
2026 148 0.7%19,673,262 2,912 1.8%333
2027 149 0.7%19,892,894 2,964 1.8%339
2028 152 2.0%19,876,216 3,021 1.9%344
2029 155 2.0%19,862,920 3,079 1.9%352
2030 156 0.6%20,124,445 3,139 2.0%359
Page 46 2011 Integrated Resource Plan
Idaho Power Company Appendix Al.Historical and Projected Sales and Load
Additional Firm Sales and Load*
Historical Additional Firm Sales and Load,1970—2010
Billed Sales Percent Average Load
Year (thousands of MWh)Change (MW)
1970 319 36
1971 295 -7.5%34
1972 284 -3.7%32
1973 291 2.2%33
1974 282 -2.9%32
1975 314 11.1%36
1976 277 -11.8%31
1977 311 12.4%36
1978 357 14.9%41
1979 373 4.3%43
1980 360 -3.4%41
1981 377 4.7%43
1982 367 -2.5%42
1983 425 15.8%49
1984 466 9.6%53
1985 471 1.1%54
1986 483 2.5%55
1987 503 4.2%57
1988 531 5.6%60
1989 671 26.5%77
1990 625 -6.8%71
1991 661 5.7%75
1992 681 3.0%78
1993 689 1.2%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 1,119 -2.1%128
2002 1,139 1.8%130
2003 1,120 -1.6%128
2004 1,157 3.3%132
2005 1,176 1.6%134
2006 1,189 1.2%136
2007 1,142 -4.0%130
2008 1,114 -2.4%127
2009 965 -13.4%110
2010 907 -6.1%103
*Includes Micron Technology,Simplot Fertilizer,INL,City of Weiser,
and Raft River Rural Electric Cooperative,Inc.
2011 Integrated Resource Plan Page 47
Appendix Al.Historical and Projected Sales and Load Idaho Power Company
Additional Firm Sales and Load*
Projected Additional Firm Sales and Load,2011—2030
Billed Sales Percent Average Load
Year (thousands of MWh)Change (MW)
2011 1,449 59.9%165
2012 1,627 12.3%185
2013 1,799 10.6%205
2014 1,902 5.7%217
2015 2,002 5.3%229
2016 2,071 3.4%236
2017 2,065 -0.3%236
2018 2,070 0.2%236
2019 2,075 0.2%237
2020 2,073 -0.1%236
2021 2,075 0.1%237
2022 2,082 0.3%238
2023 2,089 0.4%238
2024 2,096 0.3%239
2025 2,101 0.2%240
2026 2,112 0.5%241
2027 2,113 0.0%241
2028 2,119 0.3%241
2029 2,119 0.0%242
2030 2,125 0.3%243
*lncludes Micron Technology,Simplot Fertilizer,INL,Hoku Materials,
“Special”,and Raft River Rural Electric Cooperative,Inc.
Page 48 2011 Integrated Resource Plan
Idaho Power Company Appendix Al.Historical and Projected Sales and Load
Company System Load (excluding Astaris)
Historical Company System Sales and Load,1970—2010
(weather-adjusted)
Billed Sales Percent Average Load
Year (thousands of MWh)Change (MW)
1970 3,915 494
1971 4,279 9.3%539
1972 4,540 6.1%573
1973 5,027 10.7%634
1974 5,461 8.6%690
1975 6,001 9.9%758
1976 6,395 6.6%806
1977 6,817 6.6%858
1978 7,199 5.6%912
1979 7,766 7.9%976
1980 7,796 0.4%977
1981 8,066 3.5%1,015
1982 8,033 -0.4%1,009
1983 8,009 -0.3%1,012
1984 8,144 1.7%1,018
1985 8,367 2.7%1,053
1986 8,382 0.2%1,050
1987 8,434 0.6%1,056
1988 8,813 4.5%1,104
1989 9,257 5.0%1,164
1990 9,507 2.7%1,201
1991 9,740 2.5%1,218
1992 9,949 2.1%1,254
1993 10,237 2.9%1,275
1994 10,599 3.5%1,340
1995 11,045 4.2%1,375
1996 11,387 3.1%1,437
1997 11,669 2.5%1,469
1998 12,116 3.8%1,517
1999 12,461 2.8%1,564
2000 12,888 3.4%1,627
2001 13,022 1.0%1,592
2002 12,745 -2.1%1,593
2003 13,000 2.0%1,633
2004 13,287 2.2%1,668
2005 13,571 2.1%1,703
2006 13,906 2.5%1,738
2007 14,336 3.1%1,795
2008 14,439 0.7%1,810
2009 13,933 -3.5%1,746
2010 13,758 -1.3%1,732
2011 Integrated Resource Plan Page 49
Appendix Al.Historical and Projected Sales and Load Idaho Power Company
Company System Load (including Astaris)
Historical Company System Sales and Load,1970—2010 Astaris Sales and Load (1 970—2002)
(weather-adjusted)
Percent
Change
Percent
Change
Billed Sales Average Load Astaris Sales Average Load
Year (thousands of MWh)(MW)(thousands of MWh)(MW)_____
1970 5,572 693 1,657 189
1971 5,787 3.9%720 1,508 -9.0%172
1972 6,359 9.9%791 1,819 20.6%207
1973 6,672 4.9%831 1,645 -9.6%188
1974 7,105 6.5%887 1,643 -0.1%188
1975 7,558 6.4%945 1,557 -5.3%178
1976 7,970 5.5%995 1,575 1.2%179
1977 8,234 3.3%1,028 1,418 -10.0%162
1978 8,741 6.2%1,097 1,542 8.8%176
1979 9,160 4.8%1,143 1,395 -9.6%159
1980 9,309 1.6%1,157 1,513 8.5%172
1981 9,700 4.2%1,211 1,634 8.0%186
1982 9,587 -1.2%1,195 1,554 -4.9%177
1983 9,619 0.3%1,205 1,610 3.6%184
1984 9,845 2.4%1,221 1,701 5.7%194
1985 9,980 1.4%1,247 1,614 -5.1%184
1986 9,935 -0.5%1,236 1,554 -3.7%177
1987 10,126 1.9%1,259 1,692 8.9%193
1988 10,448 3.2%1,300 1,635 -3.4%186
1989 10,961 4.9%1,368 1,703 4.2%194
1990 11,111 1.4%1,394 1,604 -5.8%183
1991 11,349 2.1%1,411 1,609 0.3%184
1992 11,519 1.5%1,442 1,570 -2.4%179
1993 11,674 1.3%1,448 1,437 -8.4%164
1994 12,019 3.0%1,510 1,420 -1.2%162
1995 12,612 4.9%1,563 1,567 10.4%179
1996 13,076 3.7%1,639 1,689 7.8%192
1997 13,297 1.7%1,664 1,628 -3.6%186
1998 13,389 0.7%1,670 1,273 -21.8%145
1999 13,512 0.9%1,690 1,051 -17.4%120
2000 13,942 3.2%1,753 1,054 0.3%120
2001 13,681 -1.9%1,671 658 -37.5%75
2002 12,757 -6.8%1,594 11 -98.3%1
2003 13,000 1.9%1,633 0 -100.0%0
2004 13,287 2.2%1,668 0 0.0%0
2005 13,571 2.1%1,703 0 0.0%0
2006 13,906 2.5%1,738 0 0.0%0
2007 14,336 3.1%1,795 0 0.0%0
2008 14,439 0.7%1,810 0 0.0%0
2009 13,933 -3.5%1,746 0 0.0%0
2010 13.758 -1.3%1.732 0 0.0%0
Page 50 2011 Integrated Resource Plan
Idaho Power Company Appendix Al.Historical and Projected Sales and Load
Company System Load
Projected Company System Sales and Load,2011—2030
Billed Sales Percent Average Load
Year (thousands of MWh)Change (MW)
2011 14,521 5.5%1,819
2012 14,803 1.9%1,852
2013 15,093 2.0%1,890
2014 15,437 2.3%1,932
2015 15,751 2.0%1,970
2016 15,991 1.5%1,998
2017 16,174 1.1%2,023
2018 16,348 1.1%2,045
2019 16,545 1.2%2,070
2020 16,726 1.1%2,090
2021 16,898 1.0%2,114
2022 17,098 1.2%2,139
2023 17,313 1.3%2,166
2024 17,511 1.1%2,189
2025 17,694 1.0%2,214
2026 17,912 1.2%2,241
2027 18,084 1.0%2,263
2028 18,385 1.7%2,298
2029 18,606 1.2%2,329
2030 18,870 1.4%2,362
2011 Integrated Resource Plan Page 51
Appendix Al.Historical and Projected Sales and Load Idaho Power Company
Contract Off-System Load
Historical Contract Off-System Sales and Load,1970—2010
Billed Sales Percent Average Load
Year (thousands of MWh)Change (MW)
1970 386 44
1971 439 13.6%50
1972 448 2.0%51
1973 489 9.3%56
1974 501 2.3%57
1975 568 13.5%65
1976 613 7.9%70
1977 659 7.5%75
1978 684 3.7%78
1979 759 11.1%87
1980 762 0.3%87
1981 752 -1.2%86
1982 736 -2.2%84
1983 710 -3.5%81
1984 747 5.2%85
1985 779 4.3%89
1986 670 -13.9%77
1987 644 -4.0%73
1988 675 4.9%77
1989 740 9.7%84
1990 968 30.8%111
1991 1,537 58.8%175
1992 1,348 -12.3%154
1993 1,557 15.5%178
1994 1,811 16.3%207
1995 1,583 -12.6%181
1996 1,285 -18.8%146
1997 674 -47.5%77
1998 716 6.2%82
1999 568 -20.6%65
2000 587 3.3%67
2001 538 -8.4%61
2002 454 -15.7%52
2003 346 -23.6%40
2004 19 -94.4%2
2005 10 -47.0%1
2006 0 -1 00.0%0
2007 0 0.0%0
2008 0 0.0%0
2009 0 0.0%0
2010 0 0.0%0
Projected Contract Off-System Sales and Load,2011—2030
201 1—2030 0 0.0%0
Page 52 2011 Integrated Resource Plan
Idaho Power Company Appendix Al.Historical and Projected Sales and Load
Total Company Load
Historical Total Company Sales and Load,1970—2010
(weather-adjusted)
Billed Sales Percent Average Load
Year (thousands of MWh)Change (MW)
1970 5958 738
1971 6,226 4.5%772
1972 6,807 9.3%844
1973 7,162 5.2%889
1974 7,605 6.2%946
1975 8,126 6.8%1,012
1976 8,583 5.6%1,067
1977 8,894 3.6%1,106
1978 9,425 6.0%1,178
1979 9,920 5.2%1,233
1980 10,071 1.5%1,247
1981 10,453 3.8%1,300
1982 10,323 -1.2%1,282
1983 10,329 0.1%1,289
1984 10,592 2.5%1,309
1985 10,759 1.6%1,339
1986 10,605 -1.4%1,315
1987 10,770 1.5%1,335
1988 11,123 3.3%1,379
1989 11,701 5.2%1,455
1990 12,079 3.2%1,508
1991 12,886 6.7%1,592
1992 12,867 -0.1%1,601
1993 13,231 2.8%1,632
1994 13,830 4.5%1,724
1995 14,195 2.6%1,750
1996 14,361 1.2%1,790
1997 13,971 -2.7%1,744
1998 14,105 1.0%1,754
1999 14,081 -0.2%1,757
2000 14,529 3.2%1,822
2001 14,219 -2.1%1,735
2002 13,210 -7.1%1,648
2003 13,347 1.0%1,674
2004 13,306 -0.3%1,670
2005 13,581 2.1%1,704
2006 13,906 2.4%1,738
2007 14,336 3.1%1,795
2008 14,439 0.7%1,810
2009 13,933 -3.5%1,746
2010 13,758 -1.3%1,732
2011 Integrated Resource Plan Page 53
Appendix Al.Historical and Projected Sales and Load Idaho Power Company
Total Company Load
Projected Total Company Sales and Load,2011—2030
Billed Sales Percent Average Load
Year (thousands of MWh)Change (MW)
2011 14,521 5.5%1,819
2012 14,803 1.9%1,852
2013 15,093 2.0%1,890
2014 15,437 2.3%1,932
2015 15,751 2.0%1,970
2016 15,991 1.5%1,998
2017 16,174 1.1%2,023
2018 16,348 1.1%2,045
2019 16,545 1.2%2,070
2020 16,726 1.1%2,090
2021 16,898 1.0%2,114
2022 17,098 1.2%2,139
2023 17,313 1.3%2,166
2024 17,511 1.1%2,189
2025 17,694 1.0%2,214
2026 17,912 1.2%2,241
2027 18,084 1.0%2,263
2028 18,385 1.7%2,298
2029 18,606 1.2%2,329
2030 18,870 1.4%2,362
Page 54 2011 Integrated Resource Plan