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Home My WebLink About200610022006 IRP Appendix A.pdfD ;: ~ ' \...-...J L.. . ~,. 2006 SEP 29 Pr1 4: ';0 An IDACORP company endix A-Sales ~!-~ I ti) \..I ;,II.(l0'01\""" For the 2006 Integrated esource Pan IPC-O6- Appendix A-Sales and Load Forecast For the 2006 Integrated Resource Plan IDAHO~POWERw An IDACORP Company , . Printed on recycled paper Idaho Power Company Appendix A-Sales and Load Forecast TABLE OF CONTENTS Lis t 0 f Tab 1 es ....................................................................................................................."....................... i i Lis t 0 f Figures.. .. .. .. .. .. .. .. . . .. .. . . . .. . .. .. .. .. .. .. .. . .. .. .... .. .. .. .. . .. . .. .. .. .. .. .. . .. . .. .. .. .. .. .... .. .. .. .. .. .. .. . .. .. .. .. .. .. . .... .. .. .. .... '" ... i i List of Appendices ............... ........ ............. ............ ..... ......... """""""" ............... .............................. .......... iii Introduction...........................................................................................,...................................................... 2006 IRP versus 2004 IRP ....................... ................. .......... .................. ....."........... ........... ..... ................ ..... Average Load Comparisons................................................................................................................... Peak Hour Comparisons ........................................................................,............................................... Overview of the Forecast............................................................................................................................. Fuel Prices...... ........................................................................................................................................ Forecast Probabilities................. ,....................................................,...................................................... Load Forecasts Based on Weather Variability....................................................... .......................... Load Forecasts Based on Economic Uncertainty ............................................................................ Residential. ....... ............................. ........................... ..................... """""""'" ........... ......... ..... ..................... Commercial.................................................................. :............................................................................. Irrigation. ......... ......... ..... ........... .... ................. ........... ....... ............... ................. ................ ....... ....... ............ Industrial.................................................................................................................................................... Additional Firm Load .... :..........................:................................................................................................ Micron'Technology ..............................................................................,............................................... Simp lot Fertilizer ................................................................................................................................. Idaho National Laboratory (INL).........................................................,............................................... City 0 f Weiser.. . .. .. .. .. .. .. .. . . . . .. .. .. .. .. .. .. .. .. . .. .. . .. .. .. . .. .. .. .. . .. ........ . . .. .. .. .. .. .. . .. .. . . .. . . .. .. . .. .. .. .. . .. .. .. .. .. .. .. .. .. .. .. .. Raft River Rural Electric Cooperative, Inc........................................................................................ .. Company Firm Load........ .............. .................. ..... ..... ......... ........... ....... ....... ................. ......" ........... .......... Company Firm Peak ........... ......................................... ............................. .... ................ .........." ....... .......... Astaris Load................................................................................................,.............................................. Company System Load.......................................................................................................,...................... Contract Off-System Load ......... ............. ..................... ............... ..... ...."................. .........., ........................ Total Company Load ... ....... ..... ............................ ............. ...... ......,................ .."..... ........"...... ................ ... Demand-Side Management (DSM)........................................................................................................... Energy Efficiency Programs ................................................................................................................ ENERGY STAR CID Homes Northwest.......................................................................................... .. Commercial Building Efficiency ...................................................,............................................... 2006 Integrated Resource Plan Page i Appendix A-Sales and Load Forecast Idaho Power Company Industrial Efficiency....................................................................................................................... Irrigation Efficiency Rewards........................................................................................................ Demand Response Programs ............................................................................................................... A/C Cool Credit.... ........ ...... ..... ........ ....... """""""""" .......... "'" ..... ........ ................................ ....... Table 1. Table 2. Table 3. Table 4. Table 5. Table 6. Table 7. Table 8. Table 9. Irrigation Peak Rewards................................................................................................................. LIST OF TABLES Residential Fuel Price Escalation, 2005-2025. ................... ........ ........... ..... ............................... Average Load and Peak Demand Forecast Scenarios................................................................ Forecast Probabilities.............................................,................................................................... Firm Load Gro'wth ................,.................................................................................................... Residential Load Growth ........................................................................................................... Commercial Load Growth..................................................................................................... .. Irrigation Load Growth........................................................................................................... . Industrial Load Growth.............................................................,.............................................. Additional Firm Load Growth...................... ..............................."......................................... . Table 10. Firm Load Growth """"""""""""""""""""""""""""""""""""""""""""""'".................... Table 11. Firm Summer Peak Load Growth......................................................................................... ... Table 12. Firm Winter Peak Load Growth """""""""""""""""""""""""""""""""""""""""""""" .. Table 13. System Load Growth............................................................................................................. .. Table 14. Total Company Load Growth................................................................................................ .. Figure 1. Figure 2. Figure 3. Figure 4. Figure 5. Figure 6. Figure 7. Figure 8. Figure 9. " ' LIST OF FIGURES , -' Forecasted Electricity Prices...................................................................................................... Forecasted N atural GaS Prices................................................................................................... 6 Forecasted Firm Load """"""""""""""""""""""""""".................................,........................ Forecasted Residential Load...................................................................................................... Forecasted Residential Use Per Customer............................................................................ ...1 0 Forecasted Commercial Load................................................................................................ .. Forecasted Commercial Use Per Customer......... .................................................................... Forecasted Irrigation Load....................................................................................................... F orecas ted Industrial Load...................................................................................................... . Page ii 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast Figure 10. Industrial Electricity Consumption by Industry Group ........................................................... Figure 11. Forecasted Additional Firm Load ............................................................................................ Figure 12. Forecasted Firm Load ................................................................"............................................ Figure 13. Forecasted Firm Summer Peak............................................................................................ .... Figure 14. Forecasted Firm Winter Peak................................................................................................. .. Figure 15. Historical Astaris (FMC) Load.............................................................................................. .. Figure 16. Forecasted System Load..................... .......................................................... ,....................... ... Figure 17. Forecasted Contract Off-System Load by Customer ............................................................... Figure 18. Forecasted Total Load......... .................. ..... .......... ......'. .......................... ............"...... ......"...... . Figure 19. Composition of Electricity Sales............................................................................................. LIST OF ApPENDICES Appendix AI. Historical and Projected Sales and Load ........................................................................... Residential Load .................................................................................................................................. Historical Residential Sales and Load, 1970-2005 ...................................................................... . Projected Residential Sales and Load, 2006-2026 ....................................................................... . Commercial Load..........................................................................................,...................................... Historical Commercial Sales and Load, 1970-2005.................................................................... .. Projected Commercial Sales and Load, 2006-2026 .................................................,.................. .. Irrigation Load ..................................................................................................................................... Historical Irrigation Sales and Load, 1970-2005 ..........................................................................29 Projected Irrigation Sales and Load, 2006-2026........................................................................... Industrial Load............................................................................,........................................................ Historical Industrial Sales and Load, 1970-2005........................................................................ .. Projected Industrial Sales and Load, 2006-2026......................................................................... .. Additional Firm Sales and Load........................................................................................................ .. Historical Additional Firm Sales and Load, 1970-2005 ............................................................... Projected Additional Firm Sales and Load, 2006-2026................................................................ Company Firm Load.......................................................................................................,.................... Historical Company Firm Load, 1970-2005 ................................................................................. Proj ected Company Firm Load, 2006-2026................................................................................ .. Astaris Load.........................................................................,............................................................... Historical Astaris Sales and Load, 1970-2005.............................................................................. 2006 Integrated Resource Plan Page iii Appendix A-Sales and Load Forecast Idaho Power Company Proj ected Astaris Sales and Load, 2006-2026............................................................................... Company System Load............................... ..... ............. ................ ............... .................................... .... Historical Company System Sales and Load, 1970-2005............................................................. Projected Company System Sales and Load, 2006-2026..............................................................40 Contract Off-System Load.................... ................... ......................... ............................ .. ,.... ...... ........ .. Historical Contract Off-System Sales and Load, 1970-2005........................................................41 Projected Contract Off-System Sales and Load, 2006-2026......................................................... Total Company Load """""""""""""""""""""""""""..................................................................... Historical Total Company Sales and Load, 1970-2005................................................................43 Projected Total Company Sales and Load, 2006-2026.................................................................44 Appendix A2. Demand-Side Management Program Impacts ...................................................................45 Energy Efficiency Programs """""""""""""""""""""""""""'"....................................................... Energy Reductions """"""""""""""""""""""""""'""""""""""""""""""""""""""""............ ENERGY STAR CID Homes Northwest.....................................................................~...............45 Commercial Building Efficiency """""""""""""""""""""""""""'"....................................45 Industrial Efficiency.................................................................... ,............................................ Irrigation Efficiency Rewards.................................................................................................. Energy Efficiency Programs- TotaL.......................................................................................47 Peak Demand Reductions """""""""""""""""""""""""""'"..................................................... ENERGY STAR CID Homes Northwest......................................................................................4 7 ,.- Commercial Building Efficiency """"""""""""""""""""""""""'"......................................48 Industrial Efficiency... ....... .... "" ... .... ............... ... ........ ......... .......... ..... ......... ............. ......... ... .... Irrigation Efficiency Rewards.................................................................................................. Energy Efficiency Programs- TotaL.................................................................... ................... Demand Response Programs """"""""""""""""""""""""""""....................,.................................. Peak Demand Reductions............................................................................................................. . A/C Cool Credit ....................................................................................................................... Irrigation Peak Rewards........................................................................................................... Demand Response Programs-Total..................................................................................... .. Page iv 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast INTRODUCTION Idaho Power Company (Idaho Power or the Company) has prepared the 2006 Sales and Load Forecast as an appendix to its 2006 Integrated Resource Plan (IRP). The Sales and Load Forecast presents the Company s best estimate of the future demand for electricity within its service area. The forecast covers the 20-year period from 2006 through 2025. For planning purposes, the future demand for electricity by customers in the Company service area is represented by three load forecasts: (1) a 50th percentile or expected case load forecast, (2) a 70th percentile load forecast and (3) a 90th percentile load forecast. These forecasts define three possible load conditions evaluated in the 2006 IRP. The expected case total load growth rate is 1.8 percent per year over the 20-year planning period. This is 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 the Company s service area. Two additional load forecasts for the Idaho Power service area were prepared that provide a range of possible load growths for the 2006- 2025 planning period due to variable economic and demographic conditions. The high economic growth and low economic growth scenarios were prepared based upon statistical analysis to empirically reflect uncertainty inherent in the load forecast. The expected case load forecast assumes median temperatures and median rainfall. Since actual loads can vary significantly dependent upon weather conditions, two alternative scenarios were considered to address the load variability due to weather. A 70th percentile load forecast and a 90th percentile load forecast were prepared to illustrate the weather-related uncertainty inherent in forecasting electrical loads. The 70th percentile load forecast assumes monthly loads that can be exceeded in 3 out of 10 years (30 percent of the time). The 90th percentile load forecast assumes monthly loads that can be exceeded in 1 out of 10 years (10 percent of the time ). In the expected case scenario, total company load is forecast to increase to 2 464 average megawatts in the year 2025 from the 2006 forecast load of 1 746 average megawatts. The expected case forecast total load growth rate averages 1.8 percent per year over the 20 years of the planning period (2006-2025). The number of Idaho Power retail customers increased from the December 2005 level of 455 527 customers to about 683 362 customers at year-end 2025. The Company system peak load is forecast to grow to 4 627 megawatts in the year 2025 from the 2005 actual system peak of 2 961 megawatts. The highest system peak on record was 3 084 megawatts and occurred on Monday, July 24 2006 at 6:00 p.m. In the expected case scenario, the Company system peak increases at an average growth rate of 2. percent per year over the 20 years of the planning period (2006-2025). This Sales and Load Forecast is strongly influenced by the 2006 Economic Forecast developed by an independent consultant, John Church of Idaho Economics. The 2006 Economic Forecast is based on a forecast of national and regional economic activity performed by Global Insight, a national econometric consulting firm. The Global Insight economic forecast is modified by Idaho Economics to reflect anticipated service area conditions. Economic growth assumptions influence several of the individual class of service growth rates. Economic growth information for Idaho and its counties can be found in Appendix C-Economic Forecast. The number of households in the state ofIdaho is projected to grow at an annual average rate of 1.7 percent during the forecast period. Growth in the number of households within individual counties in Idaho Power service area differs from statewide household growth patterns. Service area households are derived from county-specific household 2006 Integrated Resource Plan Page 1 Appendix A-Sales and Load Forecast Idaho Power Company' forecasts. The number of households and employment projections, along with customer consumption patterns, are each used to form load projections. In addition to the economic assumptions used to drive the expected case forecast scenario several specific assumptions were incorporated in the forecasts of the individual sectors. Further discussion of these assumptions is presented in the sections of this report pertaining to these individual sectors. The future load impacts of implemented and committed Idaho Power Demand-Side Management (DSM) programs are considered within the 2006 Sales and Load Forecast. These programs and their expected impacts are addressed in more detail in the Company Demand-Side Management 2005 Annual Report. This report is Appendix B to the 2006 IRP. The expected case load forecast represents Idaho Power s most probable outcome for load growth during the planning period. However the actual path of future electricity sales will not follow exactly the 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 growth" and "low growth" scenarios provide boundaries on each side of the expected case scenario and reflect economic uncertainty. The 70th percentile and 90 percentile load forecast scenarios were developed to assist the Company in reviewing the resource requirements that would result from higher loads due to more adverse weather. Several changes in rate structure that were not considered in the development of the 2006 Sales and Load Forecast were seasonal rates time-of-use rates, and block rates that were each implemented in June of 2004. The impacts of these changes to rate structure on the Sales and Load Forecast will be considered as more time-series data is collected. During the 20-year forecast horizon there could be major changes in the electric utility industry. However, the implications of any major changes are unknown at this time and are not reflected in this forecast. The alternative sales and load scenarios of the 2006 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 sales and load is found in Appendix Al of this report. 2006 IRP VERSUS 2004 IRP Average Load Comparisons The 2006 IRP average system load forecast is lower than the 2004 IRP average system load forecast. A return to lower, more normal retail electricity prices and higher than expected residential customer growth combined to end the pause in load growth that occurred over the 2001-2004 period. The reduction in retail electricity prices and the recovery in the service area economy caused load growth to return although at a somewhat slower pace than before and starting at a lower level than previously forecast in the 2004 IRP. Significant factors that influenced the outcome of the 2006 IRP load forecast include: . ' 1.0, Regaining strength in the service area economy experienced in the past few years. A faster growth in the number of service area households as forecast by Idaho Economics. Page 2 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast Higher residential sales forecast due to a significant increase in the number of new service area households. Commercial, irrigation, and industrial load forecasts each lower than forecasts made for the 2004 IRP. The loss of the Company s largest irrigation customer, Bell Rapids, due to the purchase of its water rights by the State of Idaho. Higher retail electricity prices expected throughout forecast period, mostly the result of new generation additions. Slower growth at Micron Technology than assumed in the 2004 IRP. The long-term firm sales contract with the City of Weiser is assumed to expire December 31 , 2006 , and will not be renewed. A change to a 20-year planning period. Peak Hour Comparisons Peak-day temperatures and the growth in average loads drive the peak forecasting model regressions. The lower average load forecast in the 2006 IRP resulted, in most cases, in lower monthly peak forecast figures. However, the peak forecast results and comparisons with the 2004 IRP differ for a number of reasons that include: The update of the 12 monthly peak modei regressions using MetrixND (statistical software from RER, an Itron Company). The loss of the Company s largest irrigation customer, Bell Rapids, resulted in a peak reduction of 20-25 megawatts in June and July of each year. This 2006 IRP peak demand forecast was adjusted downward to reflect the estimated impact of the DSM programs that were selected for implementation since 2004. The modeling procedure in the 2006 IRP peak model was carefully reviewed and logic changes were made to more accurately forecast the peaks at various percentiles of temperatures. The peak model allows reaks to be calculated at 0, 10th, 20t ,30th, 40t\ 50th 60th 70th 80th 90th 95th and 100th percentiles of peak-day temperatures for each month of the year. The addition of more recent historical peak data 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. The summer peak regression models do not use the 2001 firm peak data as the 2001 voluntary load reduction program, which paid irrigators not to use electricity, impacted the 2001 peaks. The Company continues to utilize 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. OVERVIEW OF THE FORECAST The sales and load forecast is constructed by developing a separate forecast for each individual sales category. Independent sales 2006 Integrated Resource Plan Page 3 Appendix A-Sales and Load Forecast Idaho Power Company forecasts are prepared for each ofthe major customer classes: residential, commercial irrigation, and industrial. Individual energy and peak demand forecasts are developed for Micron Technology, Simplot Fertilizer Company, Idaho National Laboratory (INL), the City of Weiser, and Raft River Rural Electric Cooperative, Inc. (the electric distribution utility serving Idaho Power Company s former customers in the state of Nevada). These five special contract customers are combined into a single forecast category labeled Additional Firm Load. Lastly, the contract off-system category represents long-term contracts to supply firm energy and demand to off-system customers. The assumptions for each of the individual categories are described in greater detail in their 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 each month. Loss factors are determined by Idaho Power 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 2006 sales forecast. Idaho Power has two distinct peak periods: a winter peak resulting from space heating demand that normally occurs in December, January, or February, and a larger summer peak that normally occurs in June or July. The summer peak generally occurs when extensive air conditioning usage coincides with significant irrigation demand. Peak loads are forecast via 12 regression equations and are a function of temperature space heating saturation (winter only), air conditioning saturation (summer only), historical average load, and precipitation (summer only). The peak forecast utilizes statistically derived peak-day temperatures based on 30 or more years of climate data for each month. Peak loads for the INL, Micron Technology, Simplot Fertilizer, the City of Weiser, Raft River Rural Electric Cooperative Inc., and the firm off-system contracts are forecast based on historical analysis and contractual considerations. The primary exogenous factors in the forecast are macroeconomic and demographic data. Global Insight provides the macroeconomic forecasts. The national econometric projections are tailored to Idaho Power s service area by an independent consultant, John Church of Idaho Economics. 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 data, impact long-term trends in electricity sales. Changes in relative fuel prices can also have significant impacts on the future demand for electricity. ( ) Short-term and long-term nominal electricity price increases are generated internally from Idaho Power financial models. Global Insight 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. Page 4 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast Figure 1 illustrates the average electricity price (in cents per kWh) paid by Idaho Power residential customers over the historical period 1973-2005 and over the forecast period 2006- 2025. Both nominal and real prices are shown. Nominal electricity prices are expected to slowly climb to over nine cents per kWh by the end ofthe forecast period in 2025. Real electricity prices (inflation-adjusted) are expected to decline over the forecast period at an average rate of 0.1 percent each year. Table 1.Residential Fuel Price Escalation, 2005-2025 (average annual percent change) Electricity........................... Natural Gas .................. ..... adjusted for inflation Nominal Real* Electricity prices for Idaho Power customers were significantly higher in 2001 , 2002, and 2003 because of the Power Cost Adjustment impact on rates. Except for those three years Idaho Power s electricity prices have been historically quite stable. Over the 1990-2000 period, electricity prices rose only eight percent overall, an annual average compound growth rate of 0.8 percent each year. In June 2003 electricity prices for Idaho Power customers returned to levels much closer to normal between five and a half and six cents per kWh for residential customers. Figure 2 illustrates the average natural gas price (in dollars per therm) paid by Intermountain Gas Company s residential customers over the historical period 1973-2005. Natural gas prices remained stable and flat throughout the 1990s before moving sharply higher in 2001. Since 2001 , natural gas prices moved downward for a couple of years before again moving sharply upward in 2004 and 2005. Natural gas prices are expected to move upward again in 2006 to a price level twice as high as the prices experienced throughout the 1990s. After peaking in 2006, nominal natural gas prices are expected to trend lower over the five years that follow. Natural gas prices at the end ofthe forecast period are expected to nearly match the prices in 2005, growing at an average rate of zero percent per year over the forecast period (2005-2025). Real natural gas prices (adjusted for inflation) are expected to decline over the same period at an average rate of 2.1 percent each year. If natural gas prices continue to outpace electricity prices, as they have over the past several years, at some point the operating costs Figure 1.Forecasted Electricity Prices (cents perkWh) 5 ---- 1970 1980 1990 Nom inal Actual Real 19851975 Nominal Forecast 1995 2005 2010 2020 202520152000 2006 Integrated Resource Plan Page 5 Appendix A-Sales and Load Forecast Idaho Power Company Figure 2. Forecasted Natural Gas Prices (dollars per therm) ...----.-- -_._~-__._--_.. 1985 1990 RealNominal Actual 1995 202520152020200020052010 -- Nominal Forecast of space heating and water heating homes with electricity will become comparable with that of natural gas. Eventual price parity could have a significant impact on future electricity demands especially in the wintertime. 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 economic forecast for the Company s service area. The expected case load forecast assumes median temperatures and median precipitation , 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 dependant upon 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 heating degree days are assumed in winter and the lowest recorded levels of cooling and growing degree days 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 1948-2005 period was 1 040 HDD. The 70th percentile HDD is 1 069 HDD and would be exceeded in 3 out of 10 years. The 90th percentile HDD is 1 185 HDD and would be exceeded in 1 out of 10 years. The 100th percentile HDD (the coldest December on record) 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. Page 6 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast 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 dependant upon weather and these two scenarios allow us to carefully examine load variability and how it may impact 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 the year would be much less probable. It is the monthly forecast numbers that are being evaluated for resource planning, and one must be careful in interpreting the meaning of the annual average load figures being reported and graphed. Table 2 summarizes the load scenarios prepared for the 2006 IRP. Three average load scenarios were prepared based upon a statistical analysis of 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 upon a statistical analysis of historical peak-day temperatures. The probability associated with each individual peak demand scenario is also indicated in Table 2. The analysis of resource requirements is based on the 70th percentile average load forecast coupled with the 95th percentile peak demand forecast so that a more adverse representation of peak demands would be considered. Otherwise the expected case (50th percentile) average load forecast and the 90th percentile peak demand forecast were coupled together for consideration. Load Forecasts Based Economic Uncertainty The expected case load forecast is based on the most recent economic forecast for the Company s service area and represents Idaho Power s most probable outcome for load growth during the planning period. Two additional load forecasts for the Idaho Power service area were prepared that provide a range of possible load growths for the 2006-2025 planning period due to variable economic and demographic conditions. The high economic growth and low economic growth scenarios were prepared based upon 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 period 1979-2005. Table 2.Average Load and Peak Demand Forecast Scenarios Weather Probability Weather Probability of Exceeding Driver 90%1 in 10 years HOD, COD , GOD , Precipitation 70%3 in 10 years HOD, COD, GOD, Precipitation 50%1 in 2 years HOD , COD, GOD, Precipitation 95%1 in 20 years Peak-Day Temperatures 90%1 in 10 years Peak-Day Temperatures 50%1 in 2 years Peak-Day Temperatures Scenario Forecasts of Average Load th Percentile.............................. th Percentile.............................. Expected Case ............................ Forecasts of Peak Demand th Percentile.............................. th Percentile.............................. th Percentile.............................. 2006 Integrated Resource Plan Page 7 Appendix A Sales and Load Forecast 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 firm sales observed between 1979 and 2005. 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 , 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 (1979-2005). Two types of probability estimates are reported in Table 3. The first probability, the probability of exceeding, shows the likelihood that the actualload 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 firm 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 I-year, 5-year, and 10-year time periods are also shown in Table 3. Idaho Power Company Table 3.Forecast Probabilities Probability of Exceeding Scenario year 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 year year 10-year 20-year Low Growth...........26%26%26%26% Expected Case......48%48%48%48% High Growth ..........26%26%26%26% Firm load includes the sum of residential commercial, industrial, irrigation, as well as special contracts (excluding Astaris), the City of Weiser, and Raft River Rural Electric Cooperative, Inc. Company firm load projections are reported in Table 4 and pictured in Figure 3. The expected case firm load forecast growth rate averages 1.9 percent per year over the 20 years of the planning peri?d. The low scenario projects that firm load wIll increase at an average rate of 1.5 percent per year throughout the forecast period. The high scenario projects load growth of2.4 percent per year. The Company has experienced both the high and low growth rates in the past. These scenario forecasts provide a range of projected growth rates that cover approximately 80 percent of the probable outcomes as measured by Idaho Power Company s historical experIence. . . i:.) Table 4.Firm Load Growth (average megawatts) Growth 2015 Growth Rate (per year)2025 2005-202520052010 High............ Expected .... Low............ 693 1 993 2 210 2 724 693 1 892 2,051 2,464 693 816 937 261 2.4% Page 8 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast Forecasted Firm Load (average megawatts)900 . --~~._-_..._.--_.-------- 7 0 o-~ ~~-~---_~-------- 500 2;300 100 900 700 500 300 100 900 -- 700 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 Figure 3. High 70th Percentile Expected Case Low ,-------- -----_.._~._--_._._._---------~, , ,, , ,. , , ", , ,, , ,, , , The remainder of the 2006 Sales and Load Forecast document is organized by individual sectors. All information pertaining to a particular sector can be found under the appropriate heading. megawatts in 2005 to 796 average megawatts in 2025 , matching the expected case residential growth rate. The residential load forecasts are reported in Table 5 and shown graphically in Figure 4. RESIDENTIAL Table 5.Residential Load Growth (average megawatts) The expected case residentialload is forecast to increase from 539 average megawatts in 2005 to 774 average megawatts in 2025 , an average annual compound growth rate of 1.8 percent. In the 70th percentile scenario residential load is forecast to increase from 554 average 2005 2010 2015 2025 th Percentile ......584 658 706 838 th Percentile ......554 624 670 796 Expected Case.....539 607 651 774 Growth Rate (per year) 2005-2025 Figure 4.Forecasted Residential Load (average megawatts) 900 ------- 300 90th Percentile 70th Percentile Expected Case 800----~--- 700 600 500 400 200 ,-.....".,-..,...,..,,....,.,-,--,--,-" 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2006 Integrated Resource Plan Page 9 Appendix A-Sales and Load Forecast Idaho Power Company Sales to residential customers made up 24 percent of the Company s system sales in 1970 and 35 percent of system sales in 2005. The residential customer proportion of system sales is forecast to be approximately 34 percent in 2025. There were 380 952 residential customers as of December 2005. The number of residential customers is projected to increase to around 570 676 by December 2025. The relative customer proportions of the total company electricity sales are shown in Figure 19. The average sales per residential customer were about 10 000 kWh in 1970. Average sales increased to nearly 14 800 kWh per residential customer in 1979 before declining to 100 kWh in 2001. In 2002 and 2003 residential use per customer dropped dramatically, about 500 kWh per customer from 2001 , the result of two years of significantly higher electricity prices combined with a weak national and service area economy. The reduction in electricity prices in mid-May 2003 and a recovery in the service area economy caused residential use per customer to stabilize through 2005. However, beginning in 2007 residential use per customer is expected to return to a pattern of slow decline. The average sales per residential customer is expected to decline to approximately 12 000 kWh per year in 2025. Average annual sales per residential customer is shown in Figure 5. ' Figure 5. The residential sales forecast is based on a forecast of the number of residential customers and an econometric analysis of residential use per customer. The number of residential customers being added each year is a direct function of the number of new service area households being added each year as provided by the 2006 Economic Forecast. The customer forecast for 2005-2025 shows an average annual growth rate of 2.0 percent. The residential use per customer estimates consider several factors affecting electricity sales to residential customers. Residential use per customer is a function ofHDD (wintertime), CDD (summertime), use per customer trends and the price of electricity. The resulting forecast of residential use per customer is multiplied by the residential customer forecast to obtain the residential energy forecast. COMMERCIAL The commercial category is primarily made up ofIdaho Power Company s Small General Service and Large General Service customers. Other schedules that are considered part of the commercial category are Unmetered General Service, Street Lighting Service, Traffic Control Signal Lighting Service , and Dusk-to-Dawn Customer Lighting. Forecasted Residential Use Per Customer (weather-adjusted kWh) 000 500 000 500 14,000 - 500 000 - 500 000 500 000 I 1975 ,-----_..-~-----,_..- 1980 1985 1990 1995 ..-----. 01,1un 2000 2025 " ,," ., ; Page 1 2005 2010 2015 2020 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast In the expected case scenario, commercial load is projected to increase from 414 average megawatts in 2005 to 698 average megawatts in 2025. The average annual compound growth rate of commercial load is 2.6 percent during the forecast period. As summarized in Table 6 , the commercial load in the 70th percentile scenario is projected to increase from 419 average megawatts in 2005 to 705 average megawatts in 2025. The commercial load forecasts are illustrated in Figure 6. Table 6.Commercial Load Growth (average megawatts) 2005 2010 2015 2025 th Percentile ......428 506 568 720 th Percentile ......419 496 556 705 Expected Case.....414 491 551 698 Growth Rate (per year) 2005-2025 As of December 2005 , there were about 58 087 commercial customers. The number of commercial customers is expected to increase at an average annual growth rate of 2.3 percent reaching 91 114 customers in 2025. Commercial customers consumed nearly 17 percent of the Company s system sales in 1970 and 27 percent of system sales in 2005. The commercial customer proportion of system sales is projected to increase to nearly 31 percent of system sales by 2025. The relative customer proportions of the Company s total electricity sales are shown in Figure 19. The average consumption per commercial customer increased to a record 67 333 kWh in 2001. However, two years of significantly higher electricity prices combined with a weak national and service area ec:onomy caused a setback in the growth of commercial use per customer beginning in 2002. The reduction in electricity prices in mid-May 2003 and a slow recovery in the service area economy slowed the rate of decline in commercial use per customer through 2005. Beginning in 2006 , commercial use per customer is expected to return to an upward growth pattern, although at a slower pace than before and starting at a lower level. The average consumption per commercial customer is expected to increase to approximately 68 000 kWh per customer in 2025. Average annual use per commercial customer is pictured in Figure 7. The commercial sales forecast is based on a forecast of the number of commercial customers and an econometric analysis of commercial use per customer. The number of commercial customers being added each year is a direct function of the number of new residential customers being added. The number of Figure 6.Forecasted Commercial Load (average megawatts) 800 700 600 500 ----- 400 300 200 --- -'---~- 90th Percentile 70th Percentile Expected Case .._.------- 100 I I I '" I I I I , , , I I I I I , , , I I , I , , , I I 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2006 Integrated Resource Plan Page 11 Appendix A-Sales and Load Forecast Idaho Power Company Figure 7.Forecasted Commercial Use Per Customer (weather-adjusted kWh) 000 -~-~ 000 ~-~-_.._---- 000 000 000 000 60,000 000 ~- -_.~----- E:~~~ I I50000u ,:000 ' 1, ,1, , 1 I I ; 1975 1980 1985 1990 residential customers being added is a direct function of the number of new service area households as provided by the 2006 Economic Forecast. The commercial customer forecast for 2005-2025 shows an average annual growth rate of2.3 percent. The commercial use per customer equation considers several factors affecting electricity sales to commercial customers. Commercial use percustomer is a function ofHDD (wintertime), CDD (summertime), use per customer trends and electricity prices. The forecast of commercial use per customer is multiplied by the commercial customer forecast to obtain the commercial energy 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. The expected case irrigation load is forecast to increase hardly at all, from 186 average megawatts in 2005 to 187 average megawatts in -------~--_.--~--._---~ I ; 1995 2020 20252000200520102015 2025 , an average annual compound growth rate . hof zero percent. The expected case, 70t percentile, and 90th percentile scenarios forecast almost no growth in irrigation load over the 2005-2025 time period. In the 70th percentile scenario, irrigation load is projected to be 203 average megawatts in 2005 and 203 average megawatts in 2025. The individual irrigation load forecasts are reported in Table 7 and shown in Figure 8. The figure illustrates the poorer economic conditions and the drop-off in land development experienced by the agricultural economy in the mid-1980s. . ; Table 7.Irrigation Load Growth (average megawatts) 2005 2010 2015 2025 th Percentile ......224 224 222 225 th Percentile -....-203 202 201 203 Expected Case.....186 186 184 187 Growth Rate (per year) 2005-2025 One must be careful in interpreting the meaning of the annual average load figures being reported in Table 7 and graphed in Figure 8. The average loads being reported are calculated using the 8 760 hours of a typical year. In the highly seasonal irrigation sector, over 96 percent of the annual energy is billed during the six months from May through October, and Page 12 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast Figure 8. Forecasted Irrigation Load (average megawatts) 300 - ------ 275 ~-- -- - - --------- -.. ----.--. ...... 250 225 ------ 90th Percentile 175 - 150 ----... 125 ~----- . 70th Percentile Expected Case -~-.._------~ 100" ~"......",- ,C-'-" , "."_,,, .,.--" 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 nearly half of the annual energy is billed in just two months, July and August. During the summer, hourly irrigation loads at generation level can reach the 750-800 megawatt range. In a normal July, irrigation pumping accounts for roughly 25 percent of the energy generated during the hour of the annual system peak and 29 percent of the energy generated during the month for general business sales. Note that it is the monthly forecast figures that are being evaluated for resource planning purposes , not the annual average loads. In early 2001 wholesale electricity prices reached unprecedented levels and Idaho Power in an attempt to minimize reliance on the market, developed a voluntary load reduction program that paid irrigators not to use electricity in 2001. The voluntary load-reduction program was effective and resulted in a 30 percent reduction in 2001 irrigation sales or approximately 499 319 MWh. The 2001 irrigation sales and corresponding loads have been adjusted upward by 499 319 MWh to reflect a more normal 2001 irrigation season. In the future, Idaho Power does not anticipate that it will be necessary to implement similar load-reduction programs to irrigators. The 2006 irrigation sales forecast considers several factors affecting electricity sales to the irrigation class including temperature precipitation, spring rainfall, and the price of electricity. Considerations were made for the unusually low electricity consumption in the 200 I crop year due to the voluntary load-reduction program. 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. During the period 1970-1996, the Company experienced an increase in electricity-using irrigated acres of 179 000 acres. This growth in total electricity- using irrigated acres represented approximately a 2.9 percent average annual compound rate of growth. The Company projects no growth in irrigated acres in the service area and limited growth in sprinkler irrigation or conversion to sprinkler irrigation. Irrigation sales represented 15 percent of weather-normalized company system sales in 1970. Irrigation sales reached a maximum proportion of nearly 20 percent of company system sales in 1975-1977. In 2005 the irrigation proportion of system sales was 12 percent. By 2025 irrigation customers are projected to consume less than nine percent of company system sales. The customer load proportions are shown in Figure 19. 2006 Integrated Resource Plan Page 13 Appendix A-Sales and Load Forecast Idaho Power Company In 1970 Idaho Power had about 7 300 active irrigation accounts. By 2005 the number of active irrigation accounts had increased to nearly 17 000 and there is projected to be nearly 600 irrigation accounts at the end of the planning period in 2025. Since 1988, the Company has experienced growth in the number of irrigation customers but no growth in electricity sales (weather- adjusted). The number of customers has increased because customers are converting previously furrow-irrigated land to sprinkler- irrigated land. However, the conversion rate is low. Also, 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 is drawn from canals and not from deep groundwater wells. Bell Rapids has historically been the Company largest irrigation customer. The combined Bell Rapids accounts included more than 40 individual irrigation service points that accounted for approximately 3-4 percent of the Company s annual irrigation sales. In early 2005 , the State ofIdaho purchased the water rights from Bell Rapids for $24 375 000, which resulted in the loss of Bell Rapids as an irrigation customer. As a result, the irrigation sales forecast was reassessed and revised downward throughout the forecast period. In previous years, Bell Rapids had consumed on average approximately 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 of these issues, irrigation sales may be impacted. INDUSTRIAL The industrial category is made up of Idaho Power Company s Large Power Service (Schedule 19) customers with metered demands exceeding 1 000 kilowatts. There were about 50 industrial customers of Idaho Power in 1970 that represented eight percent of the Company system sales. By December 2005 the number of industrial customers had risen to 129 representing about 18 percent of system sales. In the expected case forecast, industrial load grows from 269 average megawatts in 2005 to 423 average megawatts in 2025 , an average annual growth rate of 2.3 percent (see 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. , ;".. ; Figure 9.Forecasted Industrial Load (average megawatts) 500 450 400 350 300 250 200 150 100 ' I , 1975 Expected Case --,-, ,, " I I , I , , 1985 2000 I , , , , , , , I , , I , , , , I , , , , , , I , 1990 19951980 2005 2010 2020 20252015 Page 14 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast Table 8.Industrial Load Growth (average megawatts) Growth Rate (per year)2005 2010 2015 2025 2005-2025 Expected Case..... 269 304 337 423 The industrial energy forecast is based upon service area employment projections taken from the 2006 Economic Forecast. The Company Schedule 19 customers were categorized and their historical electricity sales were summarized by economic activity. The appropriate employment series were then 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. The estimated coefficients from the industry group regression models were then applied to the appropriate employment drivers from the 2006 Economic Forecast, which resulted in the escalation of electricity sales to the various industry groups over time. Figure 10 illustrates the 2005 industrial electricity consumption by industry group. By far the largest share of electricity was consumed by the Food and Kindred Products sector (48 percent), followed by Stone, Clay, Glass, and Concrete Products (7 percent), Industrial and Commercial Machinery (6 percent), Health Services (5 percent), and Electronic and Other Electrical Equipment (5 percent). As the chart shows, several other industry groups make up the remaining share of the 2005 industrial electricity consumption. ADDITIONAL FIRM LOAD Special contracts exist for five large customers that are recognized as firm load customers. These customers are Micron Technology, Simplot Fertilizer, Idaho National Laboratory (INL), the City of Weiser, and Raft River Rural Electric Cooperative, Inc. (Raft River). Together, these customers make up the additional firm load category. In the expected case forecast, additional firm load is expected to increase from 134 average megawatts in 2005 to 163 average megawatts in the year 2025 , an average growth rate of percent per year over the planning period (see 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. Figure 10. Industrial Electricity Consumption by Industry Group (based on 2005 figures) Food and Kindred Products, 48.4% Stone, Clay, Glass, and Concrete Products, 7. Health Services. 4. Electronic and Other Electrical Equipment, 4. Educational Services, 4. Lumber and Wood Products, 3. Other Industries, 21. 2006 Integrated Resource Plan Page 15 Appendix A-Sales and Load Forecast Idaho Power Company Figure 11. Forecasted Additional Firm Load (average megawatts) 200 175 150 125 100 .-. Expected Case , , ,, , " " 1975 1980 1990 2000 "--'---'-" '1" 2005 2010 2015 202519951985 Table 9.Additional Firm Load Growth (average megawatts) Growth Rate (per year)2005 2010 2015 2025 2005-2025 Expected Case..... 134 136 145 163 Micron Technology Micron Technology is currently the Company largest individual customer. In this forecast electricity sales to Micron Technology are expected to steadily rise throughout the forecast period. The primary driver of long-term electricity sales growth at Micron Technology is employment growth in the Electronic Equipment sector as provided by the 2006 Economic Forecast. Simplot Fertilizer The Simplot Fertilizer plant is the largest producer of phosphate fertilizer in the western United States. In August of 2002, Simplot Fertilizer closed its ammonia production facility. The ammonia plant represented about 11 MW or about one-third of the entire Simplot load. The ammonia is now being purchased on contract from an outside supplier. Offsetting the decline is the equipment required to unload and store the ammonia, which accounts for an additional 3 or 4 MW. The future electricity 2020 usage at the plant is expected to continue to increase, although at a much slower rate of growth. Employment growth in the Chemical and Allied Products sector is the primary driver of long-term electricity sales growth at Simplot Fertilizer. Idaho National Laboratory (INL) The Department of Energy provided an energy consumption and peak demand forecast through 2015 for the INL. The forecast calls for loads to slowly increase through 2012 and then remain flat throughout the remaining forecast period. Looking back over a decade ago, the annual loads at the INL were quite volatile due to operational constraints affecting the availability of their nuclear reactor to generate electricity. However, as of October 1994, the INL nuclear reactor no longer generates electricity and consequently, the amount of electricity provided by Idaho Power has increased considerably. , '(- . City of Weiser \. , The City of Weiser is surrounded by and dependent upon the economic health of the Idaho Power service area. Electricity sales to the City of Weiser are assumed to vary directly with household growth in Idaho s Washington ,,- Page 16 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast County, in which the City of Weiser resides. The long-term firm sales contract with the City of Weiser is expected to expire December 31 2006, and will not be renewed. Raft River Rural Electric Cooperative, Inc. 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 Company s former customers in the state of Nevada. Idaho Power Company 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. The closing date on the transaction was April 2, 2001. Raft River is also located entirely within Idaho Power Company load control area. The contract with Raft River expires September 30 2006. However, Raft River may renew the agreement on a year-to-year basis for five additional one-year terms which would extend service until September 30, 2011. The load forecasts in the 2006 IRP assume that the Company will continue to serve the Raft River contract over the entire planning period (2006-2025). COMPANY FIRM LOAD Firm load is the sum of the individual loads of the residential, commercial, industrial, and irrigation customers, as well as special contracts (excluding Astaris), the City of Weiser, and Raft River. Firm load excludes not only Astaris, but also all contracts to provide firm energy to off-system customers. Without the dampening effects of Astaris and expiring off-system contracts on load growth, firm load more accurately portrays the underlying growth trend within the service area than totalload, which includes both Astaris and off-system commitments. The expiration of off-system contracts also explains why the 2005 firm load figures shown in Table 10 are slightly lower than the 2005 total load figures shown in Table 14. Table 10. Firm Load Growth (average megawatts) 2005 2015 Growth Rate (per year)2025 2005-20252010 th Percentile 1 801 2 008 2 175 2 601 th Percentile 1 733 1 935 2 097 2 515 Expected Case 1 693 1 892 2 051 2,464 In the expected case forecast, total firm load is expected to increase from 1 693 average megawatts in 2005, reaching 2,464 average megawatts in the year 2025, an average growth rate of 1.9 percent per year over the planning period (see Table 10). In the 70th percentile forecast, total firm load is expected to increase from 1 733 average megawatts in 2005 reaching 2 515 average megawatts in the year 2025, an average growth rate of 1.9 percent per year over the planning period (see Table 10). The three scenarios of projected firm load are illustrated in Figure 12. COMPANY FIRM PEAK As defined here, firm peak load includes the sum of the individual coincident peak demands of the residential, commercial, industrial, and irrigation customers, as well as special contracts (excluding Astaris), the City of Weiser, and Raft River. The all-time firm summer peak demand was 084 megawatts, recorded on Monday, July 24 2006, at 6:00 p.m. The previous year s summer peak demand was 2 961 megawatts and occurred on Friday, July 22, 2005 , at 4:00 p. The summer firm peak load growth has accelerated over the past ten years as air conditioning has become standard in nearly all 2006 Integrated Resource Plan Page 17 Appendix A-Sales and Load Forecast Idaho Power Company Figure 12. Forecasted Firm Load (average megawatts) ,.----------.-..-.. ...--..-..---- ..- 90th Percentile 70th Percentile Expected Case 700 500 --_u 300 100 1 ,900 700 500 300 100 900 700 ,..,-,-, , , , I , , , , , " r,rl- ,,,~'--'- TTTT- """"" 1975 1980 1985 1990 1995 2000 2005 2010 new residential home construction and new commercial buildings. The 2001 summer peak was dampened by the nearly 30 percent cutback in irrigation load due to the 2001 voluntary load reduction program. In the 90th percentile forecast, total firm summer peak load is expected to increase from 3 044 megawatts in 2005 , reaching 4 627 megawatts in the year 2025, an average growth rate of 2.1 percent per year over the planning period (see Table 11). In the 95 th percentile forecast, total firm summer peak load is expected to increase from 3 084 --------'-, ", , ", , 2015 2020 2025 megawatts in 2005 , reaching 4 689 megawatts in the year 2025. The three scenarios of projected firm summer peak load are illustrated in Figure 13. t . Table 11.Firm Summer Peak Load Growth (megawatts) 2005 2010 2015 Growth Rate (per year)2025 2005-2025 th Percentile 3 084 3,442 3 805 4,689 th Percentile 3,044 3 396 3 754 4 627 th percentile 2 913 3 248 3 589 4,428 2.. \. ) Figure 13. Forecasted Firm Summer Peak (megawatts) 000 700 4,400 100 800 500 200 900 600 300 000 700 1 ,400 I I , I , , , , I I , I , I , I , ' , , I , , , , , , I 1975 1980 1985 1990 1995 2000 95th Percentile 90th Percentile50th Percentile '11 """ 2005 2015 2025 '- , 20202010 Page 18 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast The maximum firm winter peak demand was 342 megawatts reached in December 1998. As shown in Figure 14, historical winter firm peak load is more variable than summer firm peak load. This is because the range in peak-day temperatures in winter months is far greater than the range in peak-day temperatures in summer months. The wider spread of the winter peak forecast lines in Figure 14 illustrates the higher variability associated with winter peak-day temperatures. In the 90th percentile forecast, total firm winter peak load is expected to increase from 2 576 megawatts in 2005, reaching 3 547 megawatts in the year 2025 , an average growth rate of 1. percent per year over the planning period (see Table 12). In the 95 th percentile forecast, total firm winter peak load is expected to increase from 2 679 megawatts in 2005 , reaching 3 696 megawatts in the year 2025 , an average growth rate of 1.6 percent per year over the planning period (see Table 12). The three scenarios of projected firm winter peak load are illustrated in Figure 14. Table 12.Firm Winter Peak Load Growth (megawatts) 2005 2010 Growth Rate (per year)2025 2005-20252015 th Percentile 2,679 2 948 3 121 3 696 th Percentile 2 576 2 833 2 996 3 547 th Percentile 2 287 2 511 2 648 3 134 AST ARIS LOAD The Astaris elemental phosphorous plant located on the western edge of Pocatello, Idaho ceased large-scale production in mid-December of2001. Four months later, in April 2002, the special contract between Astaris and Idaho Power Company was temiinated. Since then Astaris (now FMC Corporation) has been billed for electric service as a Schedule 19 customer (see Industrial discussion). Therefore, Astaris load is zero (since May 1 2002 as a special contract customer). Astaris had been the Company s largest individual customer and in some past years had averaged nearly 200 megawatts each month. The historical average annual load at Astaris is presented in Figure 15. Figure 14. Forecasted Firm Winter Peak (megawatts) 800 600 3,400 200 000 800 600 2,400 200 000 800 1 ,600 1 ,400 1 ,200 ---- 000 , , " ," ". , , , , , , , , , , 1975-76 1980-81 1985-86 1990-91 1995-962000-01 2005-062010-11 2015-162020-21 2025- ..,--~-- 95th Percentile 90th Percentile 50th Percentile -----,-- _m__- 2006 Integrated Resource Plan Page 19 Appendix A-Sales and Load Forecast Idaho Power Company Figure 15. Historical Astaris (FMC) Load (average megawatts) 250 225 200 175 150 125 100 - ------------~----- ,~-------_._--.------.-----, " ",' ,,. 1975 1980 1985 1990 1995 2000 COMPANY SYSTEM LOAD System load historically has been made up of firm load plus Astaris load, but has excluded long-term off-system contracts. Since Astaris ceased production in April 2002 , system load and firm load have been identical. The expected case system load forecast is based upon an economic forecast for 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 1.9 percent per year over the 2005- 2025 time period. Company system load , , ", ,, ,, , , , , , 2005 2025201020152020 projections are reported in Table 13 and shown in Figure 16. " . Table 13.System Load Growth (average- megawatts) 2005 2015 Growth Rate (per year)2025 2005-20252010 th Percentile 1 801 2 008 2 175 2 601 th Percentile 1 733 1 935 2 097 2 515 Expected Case 1,693 1 892 2 051 2,464 ~ ; In the expected case forecast, Company system load is expected to increase from 1 693 average megawatts in 2005 , to 2 464 average megawatts ( ; Figure 16. Forecasted System Load (average megawatts) 700 500 300 - ; 90th Percentile 70th Percentile Expected Case 100 900 700 500 300 100 900, 1975 2000 "-" 1980 1985 1990 1995 2005 2010 2015 2020 2025 Page 20 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast in the year 2025. In the 70th percentile forecast Company system load is expected to increase from 1 733 average megawatts in 2005 reaching 2 515 average megawatts in the year 2025-an average growth rate of 1.9 percent per year over the planning period (see Table 13). 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 with a duration greater than one year and effective during the forecast period. At this time, there are no long-term contracts that remain. The last long-term contract-with Colton, California-expired in May 2005 and was not renewed. Long-term contracts with Washington City and Utah Associated Municipal Power Systems (UAMPS) expired in June 2002 and December 2003 , respectively, and were not renewed. As illustrated in Figure 17, 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 the Company s surplus energy diminished due to retail load growth. TOTAL COMPANY LOAD Accompanied by an outlook of moderate economic growth for the Idaho Power service area throughout the forecast period, the 2006 Sales and Load Forecast projects continued growth in the Company s total load. Total load is made up of system load plus long-term firm off-system contracts. As previously mentioned, the remaining long-term off-system contract with Colton, California expired in May 2005 and was not renewed. Total company load projections are listed in Table 14 and illustrated in Figure 18. The expected case scenario average growth rate of 9 percent per year represents the most probable outlook expected by the Company. In the 70th percentile forecast, Company total load is expected to increase from 1 734 average megawatts in 2005 and reach 2 515 average megawatts in the year 2025. Figure 17. Forecasted Contract Off-System Load by Customer (average megawatts) ----..-.. 250 200 150 100 92 '93 '94 '95 '96 '97 '98 '99 '00 '01 '02 '03 '04 '05 ' EJ Colton rIJ Sierra Pacific III Washington City (1TI Elko I'll UAMPS II Montana GTECC 2006 Integrated Resource Plan Page 21 Appendix A-Sales and Load Forecast Idaho Power Company Figure 18. Forecasted Total Load (average megawatts) 700 --------- 500 300 -....------ ---- 90th Percentile 70th Percentile Expected Case ==-~ 100 1 ,900 700 ------. 500 1 ,300 -.. 100 ! j-- -----..----........--, , , 900 , "'" "'" "'" '" , , , I 1975 1980 1985 1990 1995 2000 2005 2010 Table 14.Total Company Load Growth (average megawatts) 2005 Growth Rate (per year)2025 2005-202520102015 th Percentile 1 802 2 008 2 175 2 601 th Percentile 1 734 1 935 2 097 2 515 Expected Case 1 694 1 892 2 051 2,464 The composition of total company electricity sales by year is shown in Figure 19. Residential sales are forecast to be over 43 percent higher in 2025, gaining nearly 2.0 million MWh over 2005. Commercial sales are expected to be , , 2015 20252020 nearly 68 percent higher or nearly 2.5 million MWh above 2005 followed by industrial (57 percent higher or nearly 1.3 million additional MWh) and irrigation (only 0.2 percent higher in 2025). Electricity sales to Astaris, as a special contract customer, ended in April 2002. The additional firm sales category (which represents sales to Micron Technology, Simplot Fertilizer, INL, City of Weiser, and Raft River) is forecast to grow by nearly 21 percent over the 2005-2025 time period. '-.. Figure 19. Composition of Electricity Sales (thousands of fvM/h) 1985 1990 1995 ..,, .. L . " . 2000 20102005 2020 20252015 li1!l Residential. Commercial EiJ Industrial D Irrigation ill Additional Firm Sales ~ Astaris II Firm Off~System Page 22 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast DEMAND",SIDE ~AANAGEMENT (DS~A) The future load impacts of implemented and committed Idaho Power DSM programs are conSidered within the 2006 Sales and Load Forecast. The six programs that were identified for implementation in the 2004 IRP were in place and operating by the end of2005. The four Energy Efficiency programs-ENERGY STARCIDHomes Northwest, Commercial Building Efficiency, Industrial Efficiency, and Irrigation Efficiency Rewards-resulted in a savings of 13 946 MWh in 2005. The two Demand Response programs, A/C Cool Credit and Irrigation Peak Rewards, resulted in a combined reduction of peak demand of over 43 MW in the summer of2005. The forecasts of the energy and peak demand impacts associated with each of the four Energy Efficiency programs and the peak demand impacts of the two Demand Response programs have been subtracted from the load forecast. The final load forecast (adjusted downward for DSM) will be used in all studies and analysis related to the 2006 IRP. The energy and peak demand estimates associated with each of the six implemented and committed DSM programs are included in Appendix A2. DSM energy and peak demand estimates are typically measured at the point of delivery (customers' meters). In order to make the numbers comparable to supply-side resources which are typically measured at the point of generation, the DSM numbers are increased by the amount of energy lost in transmission from the generation source to the customers' point of use. Brief descriptions of the four Energy Efficiency programs and the two Demand Response programs follow. Energy Efficiency Programs DSM Energy Efficiency initiatives were developed for all of Idaho Power customer sectors including residential, commercial industrial, and irrigation. A common theme of the Energy Efficiency programs is the focus on identifying significant segments within the customer base where prevalent energy practices can be modified to deliver desired energy savmgs. ENERGY STARrEJ Homes Northwest The ENERGY STARCID Homes Northwest Program is a regionally coordinated initiative supported in partnership between Idaho Power the Northwest Energy Efficiency Alliance (NEEA), and the Idaho Energy Division in support of improved construction practices of single-family homes. The energy goal of the program is to provide homes that are 30 percent more energy-efficient than those built to standard Idaho residential building codes. Idaho Power s energy focus for the program is to reduce future peak summer demand by increasing the efficiency of residential building envelope construction practices and increasing the efficiency of summer air conditioning use. Commercial Building Efficiency The Commercial Building Efficiency program targets those commercial customers involved in significant construction projects to which energy-efficient technologies and methods can be applied. Industrial Efficiency The Industrial Efficiency program is offered to large commercial and industrial customers of Idaho Power in both Idaho and Oregon. The program targets the acquisition of peak demand and energy savings from efficiency projects at customer sites through evaluation of existing facilities. 2006 Integrated Res6urce Plan -Page 23 Appendix A-Sales and Load Forecast Idaho Power Company Irrigation Efficiency Rewards . The Irrigation Efficiency Rewards program is designed to improve the energy efficiency of water-pumping systems in Idaho Power service area. The program provides a wide range of financial incentives and educational programs designed to serve the diversity of irrigators needs. Demand Response Programs The goal of DSM Demand Response programs at Idaho Power is to reduce the summer peak demand periods and at the same time reduce the need for high-cost supply-side alternatives such as combustion turbines or open market electricity purchases. The Demand Response programs at Idaho Power consist of A/C Cool Credit and Irrigation Peak Rewards. AlC Cool Credit A/CCool Credit is a voluntary program for residential customers. The program enables Idaho Power to directly address summer peaking requirements by reducing air conditioning load at critical high-demand periods in the summertime. Control of the air conditioning units is achieved through the installation of individual radio-controlled switches on customer equipment and is cycled on and off using a predetermined schedule. Irrigation Peak Rewards The Irrigation Peak Rewards program was developed as a pilot program in the summer of 2004 and expanded to a system~wide program in late 2005. The program was developed after selection through the 2004 IRP process. " ) The voluntary program targets irrigation customers with pumps of 100 horsepower or greater with an objective 'of reducing peak electrical demand during summer weekday afternoons by providing control over the timing and operation of irrigation pumps. The program utilizes electronic time-activated switches to turn off pumps of participating irrigation customers during predetermined intervals. ( - An expanded and more thorough description of each of the DSM programs listed above is included as Appendix B-Demand-Side Management 2005 Annual Report of the 2006 Integrated Resource Plan. ,: ," . Page 24 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast Appendix A Historical and Projected Sales and Load Residential Load Historical Residential Sales and Load , 1970-2005 (weather-adjusted) Percent kWh per Billed Sales Percent Average Load Year Customers Change Customer (thousands of MWh)Change (megawatts) 1970 132 135 983 319 152 1971 138 071 538 1 ,455 10.167 1972 145 208 956 591 184 1973 152 957 524 763 10.202 1974 160 151 064 932 223 1975 167 622 943 170 12.250 1976 175 720 13,464 366 271 1977 184 561 13,681 525 6.7%290 1978 194 650 288 781 10.2%321 1979 202 982 764 997 342 1980 209 629 637 068 2.4%350 1981 213,579 384 072 350 1982 216 696 14,424 126 357 1983 219 849 366 158 363 1984 222 695 153 3~ 152 0.2%357 1985 225 185 065 167 362 1986 227 081 , 162 216 367 1987 228 868 077 222 366 1988 230 771 328 306 377 1989 233 370 357 351 384 1990 238 117 307 3,407 392 1991 243 207 14,470 519 401 1992 249 767 133 530 407 1993 258 271 3.4%204 669 414 1994 267 854 985 746 433 1995 277 131 004 881 438 1996 286,227 758 938 456 1997 294 674 679 031 2.4%463 1998 303,300 685 151 474 1999 312 901 13,585 251 2.4%487 2000 322,402 13,370 310 1.4%499 2001 331 009 124 344 475 2002 339 764 610 284 1.4%488 2003 349 219 631 4,411 506 2004 360,462 672 568 523 2005 373 602 643 724 3.4%539 2006 Integrated Resource Plan Page 25 Appendix A-Sales and Load Forecast Idaho Power Company Residential Load Projected Residential Sales and Load , 2006-2026 Percent kWh per Billed Sales Percent Average Load Year Customers Change Customer (thousands of MWh)Change (megawatts) 2006 385 386 3.2%623 865 556 2007 396 087 704 032 3.4%575 2008 406 510 632 135 587 2009 416 185 2.4%555 225 596 2010 425 030 526 324 607 2011 433 670 12,413 383 614 2012 442 363 250 5,419 618 2013 451 236 235 521 629 2014 459 848 219 619 640 2015 468 344 201 714 651 2016 476 957 183 811 663 2017 485 832 165 910 674 2018 494 980 147 013 685 2019 504 264 128 116 697 2020 513 764 109 221 709 2021 523 563 090 330 722 " ' 2022 533,702 071 6,442 734 2023 544 002 051 556 747 2024 554,428 031 671 761 2025 565 000 013 787 ' 1.774 2026 575,794 994 906 787 \..,.. ,.. . Page 26 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast Commercial Load Historical Commercial Sales and Load , 1970-2005 (weather-adjusted) Percent kWh per Billed Sales Percent Average Load Year Customers Change Customer (thousands of MWh)Change (megawatts) 1970 375 769 914 105 1971 077 387 002 115 1972 585 140 042 120 1973 286 141 121 128 1974 096 025 181 5.4%136 1975 045 215 283 147 1976 034 509 367 157 1977"112 52,413 1,421 162 1978 831 52,468 1-,460 169 1979 087 392 584 180 1980 797 137 559 178 1981 29,567 279 605 184 1982 167 125 633 186 1983 30,776 585 618 186 1984 554 232 680 191 1985 32,417 864 746 200 1986 208 2.4%399 773 203 1987 975 932 798 1.4%205 1988 723 2.2%206 882 215 1989 638 277 970 226 1990 785 960 058 236 1991 922 899 120 243 1992 39,022 220 194 252 1993 047 600 307 261 1994 629 196 2,423 280 1995 165 545 527 287 1996 44,995 981 789 10.4%322 1997 819 981 902 333 1998 48,404 3.4%800 040 348 1999 49,430 014 164 362 2000 117 1.4%66,115 313 384 2001 501 333 3,468 383 2002 915 659 3,421 390 2003 194 2.4%333 3,486 399 2004 577 63,975 556 407 2005 145 506 629 414 2006 Integrated Resource Plan Page 27 Appendix A-Sales and Load Forecast Idaho Power Company Commercial Load Projected Commercial Sales and Load , 2006-2026 Percent kWh per Billed Sales Percent Average Load Year Customers Change Customer (thousands of MWh)Change (megawatts) 2006 072 3.4%361 802 435 2007 895 700 940 450 2008 680 834 064 464 2009 350 976 181 478 2010 65,886 2.4%237 298 491 2011 388 137 389 501 2012 899 967 4,476 511 2013 70,438 2.2%230 595 524 2014 936 65,491 711 537 2015 73,414 65,748 827 551 2016 912 000 944 2.4%564 2017 76,452 245 064 2.4%578 2018 036 66,482 188 2.4%592 2019 643 66,713 313 2.4%606 2020 81 ,284 938 5,441 2.4%621 2021 975 154 572 2.4%636 2022 718 363 707 2.4%651 2023 86,487 564 843 2.4%667 2024 273 760 981 2.4%682 2025 079 949 121 698 2026 913 131 262 715 (, " ,'" .. '\.."\.- Page 28 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast Irrigation Load Historical Irrigation Sales and Load, 1970-2005 (weather-adjusted) Percent kWh per Billed Sales Percent Average Load Year Customers Change Customer (thousands of MWh)Change (megawatts) 1970 319 112 959 827 1971 518 132 062 993 20.113 1972 815 127,402 996 113 1973 341 133 842 116 12.127 1974 971 142 631 280 14.146 1975 9,480 153 399 1,454 13.166 1976 936 153 729 527 174 1977 238 152 580 562 178 1978 10,476 153 345 606 184 1979 711 157 304 685 191 1980 854 154 154 673 191 1981 11 ,248 164 287 848 10.4%211 1982 11,312 6% . 150 192 699 194 1983 11 ,133 144 849 613 184 1984 375 129 161 1 ,469 167 1985 576 127 094 1,471 168 1986 308 128 586 1 ,454 166 1987 11 ,254 124 634 1 ,403 160 1988 378 127 821 1 ,454 166 1989 957 135 779 624 11,(3%185 1990 340 140 129 729 197 1991 12,484 1.2%135,437 691 193 1992 809 133 927 1,715 195 1993 13,078 132 056 727 197 1994 559 125,938 708 195 1995 679 124 644 1 ,705 195 1996 074 122,689 727 197 1997 383 112 330 616 6.4%184 1998 695 113,198 663 190 1999 912 116 149 1 ,732 198 2000 253 121 792 858 211 2001 15,522 109 994 707 195 2002 15,840 104 078 649 3.4%188 2003 020 105 345 688 2.4%193 2004 297 103,074 680 191 2005 936 96,390 632 186 2006 Integrated Resource Plan Page 29 Appendix A-Sales and Load Forecast Idaho Power Company Irrigation Load Projected Irrigation Sales and Load , 2006-2026 Percent kWh per Billed Sales Percent Average Load Year Customers Change Customer (thousands of MWh)Change (megawatts) 2006 305 348 650 188 2007 582 966 652 187 2008 860 542 653 186 2009 137 274 655 186 2010 18,415 018 658 186 2011 690 503 654 185 2012 966 349 657 184 2013 243 225 659 184 2014 520 1.4%131 662 184 2015 799 1.4%060 664 184 2016 073 1.4%036 667 184 2017 352 1.4%82,021 669 185 2018 630 1.4%036 672 185 2019 906 082 674 185 2020 183 149 677 185 2021 21,459 78,242 679 186 2022 737 350 681 186 2023 012 76,488 684 186 2024 289 641 686 186 2025 565 815 688 187 2026 842 006 690 187 Page 30 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast Industrial Load Historical Industrial Sales and Load, 1970-2005 (weather-adjusted) Percent kWh per Billed Sales Percent Average Load Year Customers Change Customer (thousands of MWh)Change (megawatts) 1970 173,784 445 1971 10,474 941 525 17. 1972 12.944 714 615 17. 1973 12.889,056 687 11. 1974 11,464 249 739 1975 10.014 121 785 1976 681 540 858 1977 15.988 826 929 106 1978 17.9,786 753 972 111 1979 109 989 158 087 11.126 1980 112 2.7%894 706 106 125 1981 118 5.7%718 723 148 132 1982 122 504 283 162 133 1983 122 9,797 522 194 137 1984 124 369,789 282 7.4%147 1985 125 844 888 357 155 1986 129 550 145 357 155 1987 134 006,455 1,474 169 1988 133 660 183 546 176 1989 132 091,482 594 183 1990 132 12;584 200 662 190 1991 135 699 665 719 3.4%196 1992 140 3.4%650 945 770 202 1993 141 13,179 585 854 212 1994 143 616 608 948 223 1995 120 15.16,793,437 021 230 1996 103 14.4%774 093 934 221 1997 106 309 504 042 235 1998 111 378 734 145 244 1999 108 985 029 160 247 2000 107 20,433 299 191 250 2001 111 618 361 289 4.4%261 2002 111 19,441 876 156 246 2003 112 950,866 234 255 2004 117 19,417 310 269 259 2005 126 645 220 351 269 2006 Integrated Resource Plan Page 31 Appendix A-Sales and Load Forecast Idaho Power Company Industrial Load Projected Industrial Sales and Load, 2006-2026 Percent kWh per Billed Sales Percent Average Load Year Customers Change Customer (thousands of MWh)Change (megawatts) 2006 125 507 611 2,438 277 2007 126 927 990 511 284 2008 129 2.4%934 190 572 2.4%290 2009 130 20,299,574 639 297 2010 132 508 725 707 304 2011 132 968,441 768 310 2012 133 304 026 833 2.4%316 2013 136 320,410 900 323 2014 137 655 094 967 329 2015 138 987 651 034 337 2016 140 1.4%157 009 102 345 2017 141 22,490,464 171 353 2018 142 830 086 242 361 2019 143 175 985 314 2.2%369 2020 145 1.4%366 013 388 378 2021 145 887 075 3,464 386 2022 148 23,924 761 541 395 2023 149 294 134 620 404 2024 151 506 941 701 413 2025 151 053,446 783 423 2026 153 25,277 338 867 432 " .: ( i - . '\..! Page 32 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast Additional Firm Sales and Load* Historical Additional Firm Sales and Load , 1970-2005 Billed Sales Percent Average Load Year (thousands of MWh)Change (megawatts) 1970 318 1971 294 1972 284 1973 290 1974 282 1975 314 11. 1976 277 11. 1977 311 12.4% 1978 357 14. 1979 373 1980 360 1981 376 1982 368 1983 425 15. 1984 466 1985 473 1986 482 1987 503 1988 531 1989 671 26. 1990 625 1991 661 1992 681 1993 689 1994 741 1995 877 18.4%100 1996 988 12.113 1997 048 120 1998 112 127 1999 121 128 2000 143 130 2001 118 128 2002 139 130 2003 120 128 2004 157 132 2005 175 134 * Includes Micron Technology, Simplot Fertilizer, INL, City of Weiser, and Raft River Rural Electric Cooperative , Inc. 2006 Integrated Resource Plan Page 33 Appendix A-Sales and Load Forecast Idaho Power Company Additional Firm Sales and load* Projected Additional Firm Sales and load, 2006-2026 Billed Sales Percent Average LoadYear (thousands of MWh) Change (megawatts) 2006 1 183 0.6% 1352007 1 143 -3% 1312008 1 ,163 1.7% 1322009 1 177 1.3% 1342010 1 194 1.4% 1362011 1 210 1.3% 1382012 1 228 1.5% 1402013 1 241 1.1% 1422014 1 257 1.4% 1442015 1 274 1.3% 1452016 1 294 1.5% 1472017 1 307 1.0% 1492018 1 323 1.2% 1512019 1 339 1.2% 1532020 1 356 1.3% 1542021 1 369 0.1562022 1 383 1.0% 1582023 1 397 1.0% 1592024 1,413 1.2% 1612025 1,425 0.8% 1632026 1,436 0.8% 164 * Includes Micron Technology, Simplot Fertilizer, INL, City of Weiser, and Raft River Rural Electric Cooperative, Inc. \. ;- ' Page 34 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast Company Firm Load Historical Company Firm Load, 1970-2005 (weather-adjusted) Billed Sales Percent Average Load Year (thousands of MWh)Change (megawatts) 1970 823 483 1971 269 11.538 1972 527 572 1973 977 628 1974 5,415 685 1975 005 10.759 1976 395 807 1977 748 850 1978 177 6.4%910 1979 726 971 1980 766 974 1981 049 012 1982 987 004 1983 007 011 1984 049 006 1985 215 033 1986 282 040 1987 399 1.4%052 1988 719 092 1989 209 159 1990 9,482 195 1991 709 2.4%217 1992 890 246 1993 246 278 1994 10,565 335 1995 011 373 1996 375 1 ,436 1997 638 1,464 1998 111 517 1999 12,428 560 2000 816 618 2001 926 580 2002 650 583 2003 939 625 2004 228 660 2005 511 693 2006 Integrated Resource Plan Page 35 Appendix A-Sales and Load Forecast Idaho Power Company Company Firm Load Projected Company Firm Load, 2006-2026 Billed Sales Percent Average LoadYear (thousands of MWh) Change (megawatts) 13,938 3.2% 1 746278 2.4% 1 786586 2.2% 1 822878 2.0% 1 857181 2.0% 1 89215;405 1.5% 1 918613 1.4% 1 942915 1.9% 1 978216 1.9% 2 014514 1.8% 2 051817 1.8% 2 089122 1.8% 2 12817,437 1.8% 2 16717,757 1.8% 2 207083 1.8% 2 24818,413 1.8% 2 290 18,754 1.9% 2 333100 1.8% 2 37619,451 1.8% 2,419804 1.8% 2,464162 1.8% 2 509 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 .. "'- '(, - ;' "\;,~ - i.. Page 36 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast Astaris Load Historical Astaris Sales and Load , 1970-2005 Billed Sales Percent Average Load Year (thousands of MWh)Change (megawatts) 1970 657 189 1971 508 172 1972 819 20.207 1973 645 188 1974 643 188 1975 557 178 1976 575 1.2%179 1977 1,418 10.162 1978 542 176 1979 395 159 1980 513 172 1981 634 186 1982 554 -4.177 1983 610 184 1984 701 194 1985 614 184 1986 554 177 1987 692 193 1988 635 3.4%186 1989 703 194 1990 604 183 1991 609 184 1992 570 2.4%179 1993 1,437 8.4%164 1994 1,420 1.2%162 1995 567 10.4%179 1996 689 192 1997 628 186 1998 273 21.145 1999 051 17.4%120 2000 054 120 2001 658 37. 2002 98, 2003 100. 2004 2005 2006 Integrated Resource Plan Page 37 Appendix A-Sales and Load Forecast Idaho Power Company Astaris Load Projected Astaris Sales and Load, 2006-2026 Billed Sales Percent (thousands of MWh) Change0 0.Year Average Load (megawatts) 2006-2026 Page 38 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast Company System Load Historical Company System Sales and Load, 1970-2005 (weather-adjusted) Billed Sales Percent Average Load Year (thousands of MWh)Change (megawatts) 1970 5,481 682 1971 777 5.4%719 1972 347 789 1973 622 825 1974 058 881 1975 562 946 1976 970 5.4%995 1977 165 020 1978 719 095 1979 121 138 1980 279 155 1981 683 4.4%208 1982 541 191 1983 617 204 1984 750 1.4%209 1985 828 226 1986 835 226 1987 091 254 1988 355 288 1989 913 5.4%363 1990 086 388 1991 318 1,410 1992 11,460 1 ,434 1993 683 1,450 1994 985 506 1995 578 560 1996 064 638 1997 266 659 1998 384 670 1999 13,479 686 2000 870 744 2001 585 659 2002 661 584 2003 939 625 2004 228 660 2005 511 693 2006 Integrated Resource Plan Page 39 Appendix A-Sales and Load Forecast Idaho Power Company Company System Load Projected Company System Sales and Load, 2006-2026 Billed Sales Percent Average LoadYear (thousands of MWh) Change (megawatts)938 3.2% 1 746278 2.4% 1 786586 2.2% 1 822878 2.0% 1 857181 2.0% 1 89215,405 1.5% 1 918613 1.4% 1 942915 1.9% 1 978216 1.9% 2 014514 1.8% 2 051817 1.8% 2 089122 1.8% 2 12817,437 1.8% 2 167757 1.8% 2 207083 1.8% 2 24818,413 1.8% 2 29018,754 1.9% 2 333100 1.8% 2 37619,451 1.8% 2,419804 1.8% 2,464162 1.8% 2 509 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 c. ) " . Page 40 2006 Integrated Resource Plan Idaho Power Company Contract Off-System Load Historical Contract Off-System Sales and Load , 1970-2005 Billed Sales Percent Average Load Year (thousands of MWh)Change (megawatts) 1970 386 1971 439 13. 1972 448 1973 489 1974 501 1975 568 13. 1976 613 1977 659 1978 684 1979 759 11. 1980 762 1981 752 1982 736 1983 710 1984 747 1985 779 1986 670 13. 1987 644 -4. 1988 675 1989 740 1990 968 30.111 1991 537 58.175 1992 348 12.3%'154 1993 557 15.178 1994 811 16.207 1995 583 12.181 1996 285 18.146 1997 674 47. 1998 716 1999 568 20. 2000 587 2001 538 8.4% 2002 454 15. 2003 346 23. 2004 94.4% 2005 47. Appendix A-Sales and Load Forecast 2006 Integrated Resource Plan Page 41 Appendix A-Sales and Load Forecast Idaho Power Company Contract Off-System Load Projected Contract Off-System Sales and Load , 2006-2026 Billed Sales Percent Average Load (thousands of MWh) Change (megawatts)0 -100.0% 0 0.0% Year 2006 2007-2026 ( ). ' Page 42 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast Total Company Load Historical Total Company Sales and Load, 1970-2005 (weather-adjusted) Billed Sales Percent Average Load Year (thousands of MWh)Change (megawatts) 1970 867 727 1971 216 771 1972 794 842 1973 111 883 1974 559 941 1975 130 013 1976 583 067 1977 825 098 1978 9,403 176 1979 880 228 1980 041 244 1981 10,436 297 1982 10,277 278 1983 327 287 1984 10,497 297 1985 607 318 1986 506 305 1987 735 2.2%330 1988 030 367 1989 653 1 ,450 1990 055 3.4%502 1991 855 592 1992 808 0.4%593 1993 13,240 3.4%634 1994 13,796 720 1995 161 748 1996 349 789 1997 13,940 739 1998 099 754 1999 048 0.4%754 2000 14,457 813 2001 123 723 2002 13,115 638 2003 13,286 666 2004 13,248 662 2005 522 694 2006 Integrated Resource Plan Page 43 Appendix A-Sales and Load Forecast Idaho Power Company Total Company Load Projected Total Company Sales and Load, 2006-2026 Billed Sales Percent Average LoadYear (thousands of MWh) Change (megawatts)938 3.1% 1 746278 2.4% 1 786586 2.2% 1 822878 2.0% 1 857 15,181 2.0% 1 89215,405 1.5% 1 918613 1.4% 1 942 15,915 1.9% 1 978216 1.9% 2 014 16,514 1.8% 2 051817 1.8% 2 089122 1.8% 2 12817,437 1.8% 2 167757 1.8% 2 207083 1.8% 2 24818,413 1.8% 2 290754 1.9% ,333 19,100 1.8% 2 37619,451 1.8% 2,419804 1.8% 2,464162 1.8% 2 509 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 , i ;: ;. ., " !..c. , '( , Page 44 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast Appendix A2.Demand-Side Management Program Impacts Energy Efficiency Programs ENERGY ST Homes Northwest (megawatthours including losses) Energy Reductions Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Total 2006 122 113 115 104 190 305 491 495 328 119 114 128 625 2007 195 180 185 166 303 488 779 792 529 190 182 204 193 2008 268 257 253 228 418 674 072 102 722 262 250 279 5,784 2009 345 318 323 292 537 856 377 1,414 921 337 319 358 397 2010 430 396 403 366 667 066 718 751 144 421 397 447 205 2011 515 474 482 441 799 281 069 080 371.502 476 538 028 2012 598 571 567 507 930 1,496 389 2,428 621 583 557 625 872 2013 684 632 649 581 065 725 727 795 854 670 640 713 14,734 2014 772 712 728 655 202 938 083 170 076 754 719 803 612 2015 775 713 726 655 207 923 093 174 068 756 717 804 612 2016 776 738 726 663 202 926 111 129 062 755 717 808 612 2017 774 714 730 660 201 933 106 133 077 756 718 810 16,612 2018 772 713 733 656 202 934 088 138 095 754 720 807 612 2019 771 712 732 655 201 944 075 152 090 755 722 804 612 2020 773 739 725 655 205 920 088 170 065 755 716 803 612 2021 777 714 727 660 203 924 101 160 064 759 717 807 612 2022 775 714 727 664 204 929 116 134 065 757 718 810 612 2023 774 714 730 660 201 933 106 133 077 756 718 810 16,612 2024 770 736 730 654 199 942 070 147 087 754 721 802 612 2025 772 712 728 655 202 938 083 170 076 754 719 803 16,612 Commercial Building Efficiency (megawatthours including losses) Energy Reductions Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Total 2006 107 148 154 108 087 2007 119 103 126 120 157 186 262 270 186 141 116 115 900 2008 178 158 183 179 230 274 393 386 280 209 170 171 810 2009 240 206 249 243 310 376 529 521 381 282 230 233 801 2010 304 264 322 312 395 483 673 672 483 358 297 299 861 2011 371 325 398 383 489 594 816 842 593 437 366 366 980 2012 444 402 472 453 590 698 985 013 700 528 434 430 149 2013 529 454 547 532 688 811 167 173 821 623 509 505 359 2014 609 521 626 614 788 937 346 324 958 716 582 586 605 2015 607 522 630 615 783 951 337 316 962 712 582 590 605 2016 599 537 637 614 784 952 309 349 951 701 587 586 605 2017 598 521 638 612 792 949 310 362 953 704 585 582 605 2018 603 521 635 609 793 940 326 363 942 710 584 579 605 2019 608 521 629 612 791 932 341 348 943 716 585 581 605 2020 608 538 628 614 781 949 334 314 960 711 581 589 605 2021 601 522 636 616 781 955 329 329 954 707 587 590 605 2022 597 521 638 616 786 954 311 352 953 702 588 587 605 2023 598 521 638 612 792 949 310 362 953 704 585 582 605 2024 602 540 628 611 790 930 339 345 941 715 584 580 605 2025 609 521 626 614 788 937 346 324 958 716 582 586 605 . 2006 Integrated Resource Plan Page 45 Appendix A-Sales and Load Forecast Industrial Efficiency (megawatthours including losses) Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Jan 664 506 337 177 987 815 641 531 381 353 291 321 354 368 353 312 308 321 333 381 Feb 1,451 176 001 624 348 074 002 529 251 247 7,487 253 253 255 7,470 247 249 253 503 251 Mar 546 308 053 843 638 5,414 140 888 654 685 712 731 695 653 664 729 734 731 632 654 Irrigation Efficiency Rewards (megawatthours including losses) Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Jan Feb Mar Apr 1 ,498 252 013 780 534 269 991 789 554 559 506 7,492 507 544 538 557 528 7,492 523 554 Apr 137 209 276 331 386 442 497 552 552 552 552 553 553 552 551 552 552 553 552 Energy Reductions May Jun Jul Aug 538 1 579 1 607 1 549 314 2 358 2,419 2 320 064 3 130 3 228 3 052 815 3 941 4 039 3 827 567 4 734 4 827 4 613 347 5 529 5 614 5,412 156 6 272 6,435 6 172 948 7 041 7 291 6 926 682 847 8,091 7 652 631 7 883 8 078 7 653 618 7 876 7 998 7 710 688 7 896 8,033 7,743 714 7 859 8 063 7,734 720 7 824 8 101 7 696 609 7 860 8 055 7 631 611 7 891 8 045 7 689 639 7 899 8 020 7,732 688 7 896 8 033 7 743 699 7 802 8 079 7 675 682 7 847 8 091 7 652 Sep 588 368 169 979 781 581 299 113 943 958 950 942 893 904 935 969 972 942 882 943 Energy Reductions May Jun Jul Aug Sep 021 1 802 1 778 1,415 839 904 3 364 3 323 2 648 1 560 931 5 079 5 106 4 032 2 389 859 6 716 6 728 5 292 3 164 620 8 097 8 063 6,340 3 796388 9,464 9 367 7,421 4,426 130 10 832 10 700 8 527 5 022 914 12 115 12 088 9,600 5 645 730 13 393 13,463 10 631 6 299719 13,433 13,457 10,584 6 328 697 13 520 13 381 10 602 6 323 674 13 545 13 364 10 633 6 302 663 13 540 13 376 10 658 6 277682 13,461 13,431 10 667 6 273719 13,433 13,456 10 584 6 328699 13,496 13,438 10 567 6 326 697 13 520 13 381 10,602 6 323 674 13 545 13,364 10,633 6 302682 13,461 13,431 10 667 6,273 7,730 13,393 13,463 10 631 6 299 Oct 673 521 356 189 002 834 706 571 8,412 378 310 364 8,403 8,412 354 336 334 364 389 8,412 Oct 585 093 667 196 633 074 518 958 396 393 391 395 397 398 393 389 391 395 397 396 Idaho Power Company Nay 580 367 133 944 752 538 296 085 853 888 890 899 890 873 866 919 912 899 851 853 Nay 121 225 344 453 543 634 726 817 907 906 906 907 907 907 906 906 906 907 907 907 Dee 580 370 170 976 776 557 304 125 947 952 917 902 899 916 929 960 939 902 895 947 Dee Total 853 280 706 132 559 986 75,412 838 265 265 265 265 265 265 265 265 265 265 265 265 110 132 154 176 198 220 219 219 220 220 220 219 219 219 220 220 220 Total 674 328 869 834 601 368 134 901 668 668 668 668 668 668 668 668 1;)68 668 668 668 ( \, ;'- ' Page 46 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast Energy Efficiency Programs-Total (megawatthours including losses) Energy Reductions Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Total 2006 857 625 738 745 838 795 024 613 863 2,457 880 803 240 2007 826 2,464 627 675 678 396 784 030 643 944 890 2,743 702 2008 791 3,424 501 630 644 156 798 572 559 5,494 897 704 170 2009 774 158 4,432 591 522 11 ,890 673 053 8,444 004 947 677 165 2010 5,736 020 382 542 10,248 381 281 377 203 8,413 989 654 105 226 2011 718 887 317 6,480 024 868 866 15,756 971 847 015 614 123 362 2012 701 991 206 393 805 298 509 140 641 335 013 534 141 567 2013 765 632 114 8,400 616 692 273 20,494 15,433 821 051 541 159 832 2014 785 505 040 375 17,402 114 983 776 276 278 061 555 178 151 2015 9,759 502 074 382 339 189 964 728 316 239 093 565 178,151 2016 689 783 108 335 300 274 798 789 286 157 099 530 178 151 2017 9,716 508 132 316 355 323 25,814 870 274 220 109 513 178 151 2018 9,753 508 095 324 372 273 853 894 207 265 102 505 178 151 2019 771 508 047 363 395 161 948 862 209 280 10,086 520 178 151 2020 757 769 050 358 314 162 25,933 699 288 213 069 540 178 151 2021 9,713 503 125 384 294 265 913 22,744 313 191 129 577 178 151 2022 9,703 504 132 359 326 302 829 819 314 183 10,124 555 178 151 2023 9,716 508 132 316 355 323 25,814 870 274 220 109 513 178,151 2024 729 800 024 340 371 135 919 834 183 255 063 9,497 178 151 2025 785 505 040 375 17,402 114 983 776 276 278 061 555 178,151 ENERGY ST ARCS) Homes Northwest (megawatts including losses) Peak Demand Reductions Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Max 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2006 Integrated Resource Plan Page 47 Appendix A-Sales and Load Forecast Idaho Power Company Commercial Building Efficiency (megawatts including losses) Peak Demand Reductions Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Max 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 . , 2022 " . 2023 2024 2025 Industrial Efficiency (megawatts including losses) Peak Demand Reductions Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Max 2006 2007 2008 2009 2010 2011 2012 2013 \ ' 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Page 48 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast Irrigation Efficiency Rewards (megawatts including losses) Peak Demand Reductions Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Max 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Energy Efficiency Programs-Total (megawatts including losses) Peak Demand Reductions Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Max 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2006 Integrated Resource Plan Page 49 Appendix A-Sales and Load Forecast Idaho Power Company Demand Response Programs AlC Cool Credit (megawatts including losses) Peak Demand Reductions Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Max 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Irrigation Peak Rewards (megawatts including losses) Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Page 50 Jan Feb Mar Apr Peak Demand Reductions May Jun Jul Aug Sep Oct Nov Dee Max (" ,'-./ C .! 2006 Integrated Resource Plan Idaho Power Company Appendix A-Sales and Load Forecast Demand Response Programs-Total (megawatts including losses) Peak Demand Reductions Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Max 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2006 Integrated Resource Plan Page 51 Appendix A-Sales and Load Forecast Idaho Power Company Page 52 2006 Integrated Resource Plan