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Home My WebLink About20061019Revised IRP.pdfRevisf-\d October 2006 RECEIVED 2006 OCT 18 Pr1 4: 58 2006 Integrated Resource Plan IDAHU i."Jul i' UTiLlTIE~; cm\i~~liSSIOI' IPC-06- 2006 IRP (REVISED) IDAHO PCJWER~ An IDACORP company Acknowledgement Resource planning is a continuous process that Idaho Power Company constantly works to improve. Idaho Power prepares and publishes a resource plan every two years and expects the experience gained over the next few years will lead to modifications in the 20-year resource plan presented in this document. Idaho Power invited outside participation to help develop both the 2004 and 2006 Integrated Resource Plans. Idaho Power values the knowledgeable input, comments and discussion provided by the Integrated Resource Plan Advisory Council and the comments provided by other concerned citizens and customers. Idaho Power looks forward to continuing the resource planning process with its customers and other interested parties. You can learn more about Idaho Power s resource planning process at www.idahopower.com. Safe Harbor Statement This document may contain forward-looking statements, and it is important to note that the future results could differ materially from those discussed. A full discussion of the factors that could cause future results to differ materially can be found in our filings with the Securities and Exchange Commission. Printed on recycled paper Idaho Power Company Table of Contents TABLE OF CONTENTS List of Tables ............................................................................................................................................. vi List of Figures.............................................. ............................................................................................. vii List of Appendices ................................................................................................................................... viii Glossary of Terms................................................ ...................................................................................... ix 1. 2006 Integrated Resource Plan Summary .............................................................................................. Introduction............................................................................................................................................ Potential Resource Portfolios................................................................................................................. Risk Management .................................................................................................................................. Near-Term Action Plan.......................................................................................................................... Renewable Resource Education, Research and Development.............................................................. Portfolio Composition............................................................................................................................ IRP Methodology ................................................................................................................................... Public Policy Issues ............................................................................................................................... Environmental Attributes or Green Tags ......................................................................................... Emission Offsets .............................................................................................................................. Financial Disincentives for DSM Programs .................................................................................... IGCC Technology Risk.................................................................................................................... Asset Ownership .............................................................................................................................. Idaho Power Company Today ............................................................................................................. Customer and Load Growth................................................................................................................. Supply-Side Resources ........................................................................................................................ Hydro Resources............................................................................................................................ General Hells Canyon Complex Operations.................................................................................. Brownlee Reservoir Seasonal Operations...................................................................................... Federal Energy Regulatory Commission Relicensing Process...................................................... 16 Environmental Analysis................................................................................................................. Hydroelectric Relicensing Uncertainties ....................................................................................... Baseload Thermal Resources......................................................................................................... Jim Bridger............................................................................................................................... Valmy....................................................................................................................................... Boardman................................................................................................................................. Peaking Thermal Resources........................................................................................................... 2006 Integrated Resource Plan Page i Table of Contents Idaho Power Company Danskin .................................................................................................................................... Bennett Mountain..................................................................................................................... Salmon Diesel........................................ .................................................................................. Public Utility Regulatory Policies Act........................................................................................... Idaho Projects........................................................................................................................... Oregon Projects........................................................................................................................ Cogeneration and Small Power Producers (CSPP)..................................................................19 Purchased Power ............................................................................................................................ Transmission Interconnections ... ....................................................................................................... .. Description.................................................................................................................................... . Capacity and Constraints.............................................................................................................. . Brownlee-East Path ................................................................................................................. Oxbow-North Path................................................................................................................. . Northwest Path......................................................................................................................... Borah-West Path................................................................................................................... .. Midpoint-West Path............................................................................................................... . Regional Transmission Organizations ............................... ............................................................ Off-System Purchases, Sales, and Load-Following Agreements ........................................................23 Demand-Side Management.................................................................................................................. Overview of Program Performance............................................................................................. .. Planning Period Forecasts.................................................. ................................................................. . Load Forecast....................................................................................................................................... Expected Load Forecast-Economic Impacts .................................................................................28 Expected Load F orecast- Weather Impacts.................................................................................. .. Micron Technology................... .......................... ...................... ..................................................... Idaho National Laboratory............................................................................................................ . Simplot Fertilizer.......................................................................................................................... . Firm Sales Contracts..................................................................................................................... . Hydro Forecast..................................................................................................................................... Generation Forecast ............................................................................................................................. Transmission Forecast ......................................................................................................................... Fuel Price Forecasts............................................................................................................................ . Coal Price Forecast ........................................................................................................................ Natural Gas Price Forecast............................................................................................................. Page ii 2006 Integrated Resource Plan Idaho Power Company Table of Contents 4. Future Requirements............................................................................................................................ Water Planning Criteria for Resource Adequacy................................................................................ . Transmission Adequacy ....................................................................................................................... Planning Reserve Margin.....................................................................................................................3 7 Salmon Recovery Program and Resource Adequacy .......................................................................... Planning Scenarios............................................................................................................................... Average Load (Energy).................................................................................................................. Peak-Hour Load............................................................................................................................. 5. Potential Resource Portfolios...............................................................................................................43 Resource Cost Analysis ....................................................................................................................... Emission Adders for Fossil Fuel-Based Resources........................................... ................... .........44 Production Tax Credits for Renewable Generating Resources......................................................44 30- Year Nominally Levelized Fixed Cost per kW per Month ......................................................44 30- Year Nominally Levelized Cost of Production (Baseload and Peaking Service Capacity Factors) ........................................................................................................................... Resource Cost Analysis Results.....................................................................................................45 Supply-Side Resource Options......................................................................................................... ...45 Wind............................................................................................................................................... Wind Advantages.................................................................................................................... . Wind Disadvantages ................................................................................................................ Geothermal-Binary and Flash Steam Technologies...................................................................... Geothermal Advantages.......................................................................................................... . Geothermal Disadvantages.................................................................................................... .. Pulverized Coal (Regional, Wyoming, and Southern Idaho) ........................................................ Pulverized Coal Advantages .................................................................................................... Pulverized Coal Disadvantages...................................................................... ..................... ..... Advanced Coal Technologies (IGCC, CFB) and Carbon Sequestration ....................................... Advanced Coal Technology Advantages................................................................................. Advanced Coal Technology Disadvantages ............................................................................ Combined-Cycle Combustion Turbines ........................................................................................ CCCT Advantages ................................................................................................................... CCCT Disadvantages............................................................................................................... Simple-Cycle Combustion Turbines ..................... ........ .......................................... ....................... SCCT Advantages.................................................................................................................... SCCT Disadvantages............................................................................................................... 55 2006 Integrated Resource Plan Page iii Table of Contents Idaho Power Company Combined Heat and Power ............................................................................................................ CHP Advantages...................................................................................................................... CHP Disadvantages ................................................................................................................. Biomass.......................................................................................................................................... Solar Energy and Photovoltaics ..................................................................................................... 56 Nuclear........................................................................................................................................... 56 Nuclear Advantages............................................................................................................... .. Nuclear Disadvantages................................................... ............................. .......................... ... Hydroelectric.................................................................................................................................. Efficiency Upgrades at Existing Facilities..................................................................................... Transmission Path Upgrades............................................. ...................... ....................................... McNary to Locust via Brownlee.............................................................................................. Lolo to Oxbow ......................................................................................................................... Bridger, Wyoming to Boise Bench via Midpoint.................................................................... 61 Garrison or Townsend, Montana to Boise Bench via Midpoint .............................................. White Pine, Nevada to Boise Bench via Midpoint .................................................................. Transmission Advantages ........................................................................................................ Transmission Disadvantages.................................................................................................... Demand-Side Management.................................................................................................................. Demand Response Programs ......................................................................................................... Energy Efficiency Programs......................................................................................................... . Market Transformation Programs .................................................................................................. DSM Evaluation................................................................................................................................... 2006 IRP Demand-Side Programs ................................................................................................. 2006 IRP DSM Program Description and Metrics ........................................................................ Residential Efficiency Program-Existing Construction.......................................................... Commercial Efficiency Program-Existing Construction ........................................................ Industrial Efficiency Program Expansion ....................................................... ......................... General DSM Discussion....................................................................... ..................... ................... Regional DSM Savings Comparison ............................................................................................. Resource Portfolios.............................................................................................................................. 70 Portfolio Selection............................................................................................................................... 71 6. Risk Analysis ....................................................................................................................................... Selection of Finalist Portfolios................................................ ..... ... ........ ........ ........ .... ......................... Page iv 2006 Integrated Resource Plan Idaho Power Company Table of Contents Risk Analysis of Finalist Portfolios ..................................................................................................... Quantitative Risk........................................................................................................................... 77 Carbon Risk ............................................................................................................................. Natural Gas Price Risk............................................................................................................. 81 Capital and Construction Cost Risk......................................................................................... Hydrologic Variability Risk................................................................................................... .. Market Risk.............................................................................................................................. Qualitative Risk............................................................................................................................. 85 Regulatory Risk ....................................................................................................................... Declining Snake River Base Flows.......................................................................................... 86 FERC Relicensing Risk ........................................................................................................... Resource Commitment Risk .................................................................................................... Resource Siting Risk................................................................................................................ 87 Fuel, Implementation, and Technology Risks..... ................................ ............... .......... ....... .... Risk Analysis Summary...................................................................................................................... . Ten-Year Resource Plan ...................................................................................................................... Introduction.......................................................................................................................................... Supply-Side Resources ........................................................................................................................ Demand-Side Resources..................................................................................................................... . Renewable Energy............................................................................................................................... 97 Peaking Resources ............................................................................................................................... Market Purchases................................................................................................................................ . Transmission Resources....................................................................................................................... Demand-Side Management Programs................................................................................................ . Near-Term Action Plan........................................ ............. ..................................... ............................1 0 1 Introduction........................................................................................................................................l 0 1 Near-Term Action Plan......................................................................................................................l 0 1 Generation Resources........................................................................................................................l 02 Thermal Generation-Baseload...................................................................................................l 02 Thermal Generation-Peaking....................................................................................................l 03 Renewable Energy.............................................................................................................................l 03 Wind Generation..........................................................................................................................l 04 Geothermal Generation................................................................................................................l 04 Transmission Resources.....................................................................................................................l 04 2006 Integrated Resource Plan Page v Table of Contents Idaho Power Company Demand-Side Management................................................................................................................l 04 Risk Mitigation..................................................................................................................................l 05 Table 1- Table 2- Table 2- Table 2- Table 2- Table 2- Table 2- Table 3- Table 3- Table 3- Table 3- Table 4- Table 5- Table 5- Table 5- Table 5- Table 5- Table 5- Table 5- Table 5- Table 6- Table 6- Table 6- Table 6- Table 6- Table 6- Table 6- Table 6- Table 6- LIST OF TABLES 2006 Preferred Portfolio Summary and Timeline.................... ............ ................................... Historical Data (1990-2005)................................................................................................. Changes in Reported Nameplate Capacity Since 1990......................................................... Supply-Side Resources....................................................................................................... .. Hydropower Project Relicensing Schedule........................................................................... Transmission Interconnections............................................................................................ . 2005 DSM Energy and Peak Impact....................................... .................... ..........................25 Load Forecast Probability Boundaries (aMW) ................................................ ........... .......... Range of Total Load Growth Forecasts (aMW) ................................................................... Firm Sales Contracts............................................................................................................ . Recent Brownlee Inflow History ..........................................................................................31 Planning Criteria for Average Load and Peak-Hour Load ................................................... Emissions Adders for Fossil Fuel Generating Resources-Base Case...................................44 Emission Adders-Dollars per MWh (2006 Dollars)-Base Case .......................................... Potential Demand-Side Programs ......................................................................................... Summary of Residential Efficiency Program-Existing Construction .................................. Summary of Commercial Efficiency Program-Existing Construction................................. Summary of Industrial Efficiency Program Expansion ........................................................ Comparison of Initial Portfolios........................................................................................... 70 Portfolio Comparison ............................................................ .................................... ............ Summary of Primary Strengths and Weaknesses Used for Portfolio Selection................... 7 Summary of Finalist Portfolios............................................................................................. 78 Carbon Risk Analysis........................................................................................................... . Natural Gas Price Risk Analysis........................................................................................... Cost of Construction Risk Analysis ...................................................................................... Capital Risk Analysis (Discount Rate) ................................................................................. Summary Statistics of Hydrologic Variability Analysis ....................................................... Market Risk Analysis............................................................................................................ Risk Analysis Summary ........................................................... ............................................. Page vi 2006 Integrated Resource Plan Idaho Power Company Table of Contents Table 7- Table 7- Table 8- Figure 2- Figure 2- Figure 2- Figure 4- Figure 4- Figure 4- Figure 5- Figure 5- Figure 5- Figure 5- Figure 5- Figure 5- Figure 5- Figure 6- Figure 6- Figure 6- Figure 6- Figure 7- Portfolio F2 (Supply-Side and Demand-Side Resources)..................................................... Portfolio F2 (10- Year Resource Plan) ........ ....................................................................... ... Portfolio F2 (Near-Term Action Plan through 2008) .........................................................102 LIST OF FIGURES Historical Data (1990-2005)................................................................................................ . 2005 Energy Sources ............................................................................................................ Transmission System........................................................................................................... . Monthly Energy Surplus/Deficiency 70th Percentile Water, 70th Percentile Average Load (Existing and Committed Resources) ...... ......... ....... ....... ......................... .................. .. Monthly Peak-Hour Surplus/Deficiency 90th Percentile Water, 95th Percentile Peak Load (Existing and Committed Resources) ..........................................................................40 Monthly Peak-Hour Northwest Transmission Deficit 90th Percentile Water, 95th Percentile Peak Load (Existing and Committed Resources) ................................................42 30-Year Nominal Levelized Fixed Costs Cost of Capital and Fixed Operating Costs.........46 30-Year Nominal Levelized Cost of Production at Baseload Capacity Factors ...................47 30-Year Nominal Levelized Cost of Production at 4% Capacity Factors (Peaking Service) ................................................................................................................................. Transmission Plus Market Purchase Alternatives 30- Year Nominal Levelized Cost of Production at Baseload Capacity Factors................ ................................................ ....... .. Transmission Plus Market Purchase Alternatives 30- Year Nominal Levelized Cost of Production at Peaking Service Capacity Factors............................................................ .. Transmission Plus Market Purchase Alternatives 30- Year Nominal Levelized Fixed Costs Cost of Capital and Fixed Operating Costs................................................................. Existing and Potential DSM................................................................................................ .. Levelized Price for Generating Resources vs. Carbon Adder .............................................. Hydrologic Variability Portfolio Comparison ($OOOs) .... .......... ........................................... Present Value of Risk Adjusted Portfolio Costs................................................................ ... Portfolio F2 (Capacity Compared to Low, Expected, and High Peak-Hour Load Forecast) .................. ............ ........ .......................................... ............................................. ... Idaho Power Energy Sources in 2007 and 2025 ................................................................... Page vii2006 Integrated Resource Plan Table of Contents Idaho Power Company LIST OF ApPENDICES Appendix A-Sales and Load Forecast Appendix B-Demand-Side Management 2005 Annual Report Appendix C-Economic Forecast Appendix D- Technical Appendix Page viii 2006 Integrated Resource Plan Idaho Power Company Glossary of Terms GLOSSARY OF TERMS AIC - Air Conditioning AIR - Additional Information Request Alliance - Northwest Energy Efficiency Alliance aMW - Average Megawatt BOR - Bureau of Reclamation BP A - Bonneville Power Administration C&RD - Conservation and Renewable Discount CAMR - Clean Air Mercury Rule CCCT - Combined-Cycle Combustion Turbine CDD - Cooling Degree-Days CFB - Circulating Fluidized Bed CFL - Compact Fluorescent Light CHP - Combined Heat and Power CO2 - Carbon Dioxide CRC - Conservation Rate Credit CSPP - Cogeneration and Small Power Producers CT - Combustion Turbine DOE - US. Department of Energy DG - Distributed Generation DSM - Demand-Side Management EA - Environmental Assessment EEAG - Energy Efficiency Advisory Group ErA - Energy Information Administration EIS - Environmental Impact Statement ESA - Endangered Species Act FCRPS - Federal Columbia River Power System FERC - Federal Energy Regulatory Commission GDD - Growing Degree-Days HDD - Heating Degree-Days IDWR - Idaho Department of Water Resources IGCC - Integrated Gasification Combined Cycle INL - Idaho National Laboratory 2006 Integrated Resource Plan Page ix Glossary of Terms Idaho Power Company IOU - Investor-Owned Utility IPC - Idaho Power Company IPUC - Idaho Public Utilities Commission IRP - Integrated Resource Plan IRP AC - Integrated Resource Plan Advisory Council kV - Kilovolt kW - Kilowatt kWh - Kilowatt Hour LIW A - Low Income Weatherization Assistance MAF - Million Acre Feet MMBTU - Million British Thermal Units MW - Megawatt MWh - Megawatt Hour NEP A - National Environmental Policy Act NWPCC - Northwest Power and Conservation Council NOx - Nitrogen Oxides OPUC - Oregon Public Utility Commission PCA - Power Cost Adjustment PM&E - Protection, Mitigation, and Enhancement PP A - Power Purchase Agreement PTC - Production Tax Credit PUC - Public Utility Commission PURPA - Public Utility Regulatory Policies Act of 1978 PV - Present Value QF - Qualifying Facility REC - Renewable Energy Credit Rider - Energy Efficiency Rider RFP - Request for Proposal RPS - Renewable Portfolio Standard RTO - Regional Transmission Organization SO2 - Sulfur Dioxide SCCT - Simple-Cycle Combustion Turbine W ACC - Weighted Average Cost of Capital WECC - Western Electricity Coordinating Council Page x 2006 Integrated Resource Plan Idaho Power Company 2006 Integrated Resource Plan Summary 1. 2006 INTEGRATED RESOURCE PLAN SUMMARY Introduction The 2006 Integrated Resource Plan (IRP) is Idaho Power Company s eighth resource plan prepared to fulfill the regulatory requirements and guidelines established by the Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility Commission (OPUC). In developing this plan, Idaho Power worked with the Integrated Resource Plan Advisory Council (IRP AC), comprised of major stakeholders representing the environmental community, major industrial customers irrigation customers, state legislators, public utility commission representatives, the Governor s office, and others. The IRPAC meetings served as an open forum for discussion related to the development of the IRP, and its members have made significant contributions to this plan. While input from the IRP AC has been considered and incorporated into the 2006 IRP final decisions on the content of the plan were made by Idaho Power. A list of IRP AC members can be found in Appendix Technical Appendix. Idaho Power encourages IRP AC members to submit comments expressing their views regarding the 2006 IRP and the planning process. The 2006 IRP assumes that during the planning period (2006-2025), Idaho Power will continue to be responsible for acquiring resources sufficient to serve all of its retail customers in its mandated Idaho and Oregon service areas and will continue to operate as a vertically- integrated electric utility. The two primary goals of Idaho Power s 2006 IRP are to: 1. Identify sufficient resources to reliably serve the growing demand for energy within Idaho Power s service area throughout the 20-year planning period; and 2. Ensure the portfolio of selected resources balances costs, risks, and environmental concerns. In addition, there are several secondary goals: 1. Give equal and balanced treatment both supply-side resources and demand-side measures; Highlights Idaho Power uses 70th percentile water conditions and 70th percentile average load for energy planning. For peak-hour capacity planning, Idaho Power uses 90th percentile water conditions and 95th percentile peak-hour load. The 2006 IRP includes 1 300 MW (nameplate) of supply-side resource additions and DSM programs designed to reduce peak load by 187 MW and average load by 88 aMW. Idaho Power s average load is expected to increase by 40 aMW (1.9% annually); summertime peak-hour loads are expected to increase by 80 MW (2.1 % annually) per year through 2025. Idaho Power expects to add 11 000-000 retail customers per year through 2025. In July 2006, Idaho Power set a new peak-hour load record of 3,084 MW. 2006 Integrated Resource Plan Page 1 1. 2006 Integrated Resource Plan Summary Idaho Power Company 2. Involve the public in the planning process in a meaningful way; 3. Explore transmission alternatives; and 4. Investigate and evaluate advanced coal technologies. The number of households in Idaho Power service area is expected to increase from around 455 000 in 2005 to over 680 000 by the end of the planning period in 2025. Population growth in southern Idaho is an inescapable fact, and Idaho Power will need to add physical resources to meet the electrical energy demands of its growing customer base. Idaho Power, with hydroelectric generation as the foundation of its energy production, has an obligation to serve customer loads regardless of the water conditions which may occur. In light of public input and regulatory support of the more conservative planning criteria used in the 2002 IRP, Idaho Power will continue to emphasize a resource plan based upon a worse-than-median level of water. In the 2006 IRP, Idaho Power is again emphasizing 70th percentile water conditions and 70th percentile average load for energy planning, and the 90th percentile water conditions and 95th percentile peak-hour load for capacity planning. A 70th percentile water condition means Idaho Power plans generation based on a level of streamflows that is exceeded in seven out of ten years on average. Conversely, streamflow conditions are expected to be worse than the planning criterion in three out of ten years. This is a more conservative planning criterion than median water planning, but less conservative than critical water planning. Further discussion of Idaho Power s planning criteria can be found in Chapter 4. Idaho Power extended the planning horizon in the 2006 IRP to 20 years. Recent Idaho Power IRPs utilized a 10-year planning horizon, but with the increased need for base load resources with long construction lead times along with the need for a 20-year resource plan to support PURP A contract negotiations, Idaho Power and the IRP AC decided to extend the planning horizon of the 2006 IRP to 20 years. Potential Resource Portfolios Idaho Power examined 12 resource portfolios and several variations of portfolios in preparing the 2006 IRP. Discussions with the IRPAC led to the selection of four finalist portfolios for additional risk analysis-a portfolio that emphasized thermal resources , a portfolio with a strong commitment to renewable resources, a resource portfolio that emphasized regional transmission, and a modified version of the 2004 IRP preferred portfolio. Following the risk analysis, a modified version of the 2004 preferred portfolio was selected as the preferred portfolio for the 2006 IRP. The selected portfolio adds supply-side and demand-side resources capable of providing 089 MW of energy, 1 250 MW of capacity to meet peak-hour loads, and 285 MWof additional transmission capacity from the Pacific Northwest. The selected portfolio also includes demand-side management (DSM) programs estimated to reduce loads by 88 aMW annually and peak-hour loads by 187 MW. The preferred portfolio represents resource acquisition targets. It is important to note the actual resource portfolio may differ from the above quantities depending on acquisition or development opportunities, specific responses to Idaho Power s Request for Proposals (RFPs), the business plans of any ownership partners and the changing needs ofIdaho Power system. Risk Management Idaho Power, in conjunction with the IPUC staff and interested customer groups, developed a risk management policy during 2001 to protect against severe movements in Idaho Power Page 2 2006 Integrated Resource Plan Idaho Power Company 2006 Integrated Resource Plan Summary power supply costs. The risk management policy is primarily aimed at managing short-term market purchases and hedging strategies with a typical time horizon of 18 months or less. The risk management policy is intended to supplement the existing IRP process. Whereas the IRP is the forum for making long-term resource decisions, the risk management policy addresses short-term resource decisions that arise as resources, loads costs of service, market conditions, and weather vary. The Risk Management Committee oversees both the implementation of the risk management policy and the IRP to ensure the planning process is consistent and coordinated. Idaho Power intends to commit to, or acquire, a variety of resource types including renewable thermal, and combined heat and power (CHP) resources, demand-side programs, and transmission resources early in the planning period. If any of the selected resources differ from the expected levels of production or reliability, Idaho Power may need to adjust the resource proportions in later resource plans. Should market or policy conditions change dramatically, the customers of Idaho Power will have the protection of a diverse resource portfolio. Near-Term Action Plan Customer growth is the primary driving force behind Idaho Power s need for additional resources. Population growth throughout southern Idaho---specifically in the Treasure Valley-requires additional resources to meet both instantaneous peak and sustained energy needs. Idaho Power s data, projections, and analyses show that a blended, diversified portfolio of resources and full utilization of its import capability during peak-load hours is the most cost-effective, least-risk, and environmentally responsible method to address the increasing energy needs of its customers. Idaho Power has selected a balanced portfolio which adds renewable resources, demand-side measures, transmission resources, and thermal generation to meet the projected electric demands over the next 20 years. The 2006 IRP identifies the following specific actions to be taken by Idaho Power prior to the next IRP in 2008: September 2006: 2006 Integrated Resource Plan filed with the Idaho and Oregon Public Utility Commissions Fall 2006 1. Conclude 100 MW wind RFP issued in response to the 2004 IRP 2. Notify short-listed bidders in 100 MW geothermal RFP issued in response to the 2004 IRP 3. Initiate McNary-Boise transmission upgrade process 4. Develop implementation plans for new DSM programs with guidance from the Energy Efficiency Advisory Group (EEAG) 5. Continue coal-fired resource evaluation with A vista and consider expansion opportunities at Idaho Power s existing projects (Jim Bridger, Boardman, and Valmy) 6. Investigate opportunities to increase participation in the highly successful Irrigation Peak Rewards DSM program 7. Complete the wind integration study 8. Evaluate the Energy Efficiency Rider (Rider) level to fund DSM program expanSIOn 2006 Integrated Resource Plan Page 3 1. 2006 Integrated Resource Plan Summary Idaho Power Company 2007 1. Finalize DSM implementation plans and budgets with guidance from the EEAG 2. Conclude 100 MW geothermal RFP 3. Assess CHP development in progress via the PURP A process-consider issuing RFP for 50 MW CHP depending on level of PURP A development 4. Identify leading candidate site(s) for coal-fired resource addition and begin permitting activities 5. Continue study of225 MW McNary- Boise transmission upgrade 6. Bring 100 MW of wind on-line 7. Evaluatelinitiate DSM programs 8. Select coal-fired resource, finalize contracts, begin design, procurement and pre-construction activities 2008 1. Make final commitment to 225 MW McNary-Boise transmission upgrade 2. Complete 250 MW Borah-West transmission upgrade 3. Bring 170 MW Danskin expansion on-line 4. Evaluatelinitiate DSM programs 5. Prepare and file 2008 IRP The 2006 IRP has two significant supply-side resource additions that will require considerable preconstruction commitments; approximately 250 MW of coal-fired generation could come from either the expansion of an existing facility or the addition of a new generation facility and a 225 MW upgrade of the McNary to Boise transmission line. Idaho Power will continue its research efforts on these two resource additions during the fall of 2006. The preferred portfolio also includes 250 MW of advanced coal technology in the form of an integrated gasification combined-cycle (IGCC) plant in the later stages of the planning period. The timing and commitment to the IGCC or other advanced coal facility will be assessed in future resource plans when additional feasibility information should be available concerning this technology. Renewable Resource Education , Research and Development In the 2004 IRP, Idaho Power expressed its commitment to renewable energy by stating, Idaho Power will continue to fund education and demonstration energy projects with up to $100 000 of funding." One of the projects supported with this commitment was the Foothills Environmental Learning Center in north Boise. Idaho Power s support for this project included the installation of a 4.6 kW fuel cell and a 2.0 kW solar panel. In addition, Idaho Power repaired and upgraded the 15 kW solar energy project on the roof of its corporate headquarters in downtown Boise. Continuing with its commitment to support renewable energy through education and demonstration projects, Idaho Power intends to commit up to an additional $100 000 to support renewable energy education and demonstration projects. Areas currently under consideration include solar energy projects and river flow energy conversion devices. At present, Idaho Power has not selected a specific project(s) to pursue with this funding. Page 4 2006 Integrated Resource Plan Idaho Power Company 2006 Integrated Resource Plan Summary Idaho Power intends to conclude the wind integration study during the fall of 2006. Idaho Power also has an open RFP for a geothermal resource which it intends to conclude in early 2007. Idaho Power is currently negotiating a power purchase contract with the successful bidder identified for the wind RFP issued in 2005. The 2006 preferred portfolio includes 250 MW of wind resources, 150 MW of geothermal resources, and 150 MW of CHP generation resources. Portfolio Composition The resource quantities identified in the preferred portfolio approximate the generation resources Idaho Power may acquire. Each resource and each resource acquisition has different characteristics and Idaho Power may alter the resource quantities to capitalize on market conditions, acquisition or development opportunities, and the specific characteristics of the bids offered during an individual RFP. Additionally, the results of Idaho Power s wind integration study may cause either an increase or decrease in the amount of wind generation included in the preferred portfolio. Idaho Power conducts the IRP process every two years which provides an opportunity to revisit the resource portfolio and make adjustments in response to changing conditions. The diversified resource portfolio allows Idaho Power to continue to reliably serve its customers while balancing costs, risks, and environmental concerns. A summary and timeline of the 2006 preferred portfolio is listed in Table 1- IRP Methodology A brief outline of Idaho Power s IRP methodology is as follows: 1. Assess present and estimate future conditions by: Developing load, hydrologic, and generation forecasts Determining energy surplus and deficiency on a monthly and hourly basis Developing a peak-hour transmission analysis to estimate transmission deficiencies from the Pacific Northwest Determining energy (monthly) and capacity (peak-hour) targets Table 1-1. 2006 Preferred Portfolio Summary and Timeline Summary Resource 250 150 150 285 250 250 250 585 w~........................................................ Geothermal (Binary)................................ CHP........................................................ Transmission........................................... Coal......................................................... RegionallGCC CoaL............................... Nuclear.................................................... Total Nameplate DSM Peak............................................... Energy (aMW) ...................................."... Transmission........................................... Peak........................................................ 187 089 285 250 Year Timeline Resource 100 150 225 250 250 100 250 585 2008 Wind (2005 RFP) .."................. 2009 Geothermal (2006 RFP)........... 2010 CHP ......................................... 2012 Wind......................................... 2012 Transmission McNary-Boise ... 2013 Wyoming Pulverized Coal........ 2017 RegionallGCC CoaL................ 2019 Transmission Lolo-IPC ............ 2020 CHP ......................................... 2021 Geothermal.............................. 2022 Geothermal.............................. 2023 INL Nuclear .............................. Total Nameplate 2006 Integrated Resource Plan Page 5 1. 2006 Integrated Resource Plan Summary Idaho Power Company 2. Inventory the potential supply-side and demand-side options and construct numerous portfolios capable of meeting energy and capacity targets by: Estimating the costs of potential supply-side resources and demand- side programs using preliminary transmission interconnection cost estimates Constructing practical portfolios based on supply-side resources and demand-side program costs and estimates Simulating performance and determining the portfolio costs Ranking each portfolio based on the present value of expected costs and selecting finalist portfolios for further risk analysis 3. Evaluate the finalist portfolios and identify a preferred portfolio by: Refining the transmission integration cost analysis and incorporating backbone upgrades Performing qualitative and quantitative risk analyses 4. Develop near-term and 10-year action plans based on the preferred portfolio Public Policy Issues A number of public policy issues have emerged since Idaho Power filed the 2004 IRP. These issues include green tags, emission offsets financial disincentives for DSM programs technology risks, and asset ownership. Each issue significantly affects long-term resource planning and the resulting portfolio of resources acquired. The near-term actions that Idaho Power takes to position itself and its customers for potential future regulations are also affected by a range of public policy issues. Idaho Power discussed a range of public policy issues with the IRP AC and was hopeful a consensus opinion would emerge as a result of the discussions. While the topics were discussed at length, it became apparent that a consensus opinion would likely compromise individual positions on these important issues. In lieu of being able to provide recommenda- tions from the IRP AC on these issues, Idaho Power has chosen to present a series of questions and its position on each of the issues. Members of the IRP AC and the public are invited to provide specific comments on Idaho Power s proposed position on each of the topics. Public comments will help Idaho Power, the Idaho and Oregon PUCs, and the IRP AC assess the level of public support for each of the proposals. Environmental Attributes or Green Tags Due to a growing interest in renewable resources, over the past five years the electric industry has seen the output from renewable resources separated into two components delivered energy and environmental attributes. Environmental attributes are more commonly referred to as "green tags" due to the positive environmental aspects , measured in dollars-per- MWh of production, of renewable resources. The emergence of two products stemming from one resource raises policy questions that are beginning to influence resource decisions for Idaho Power and other electric utilities. The main policy questions Idaho Power associates with green tags are: Should Idaho Power acquire the green tags for any renewable energy regardless of whether the energy is generated at an Idaho Power generation unit or purchased through a purchased power Page 6 2006 Integrated Resource Plan Idaho Power Company 2006 Integrated Resource Plan Summary agreement, PURP A contract, energy exchange or some other arrangement? Should Idaho Power pay to acquire green tags even if the State of Idaho, the State of Oregon, and the federal government have no current statutory requirement for green tags through renewable portfolio standards (RPSs) or other regulations? Must Idaho Power possess green tags in order to accurately represent the renewable segments of its generation portfolio? Should future RFPs require the bidders to include green tags as part of the product and pricing? Should green tags be delivered to Idaho Power as part of any PURP A Qualifying Facility (QF) purchase? Should Idaho Power s voluntary Green Power Program express a preference to purchase green tags from developments within Idaho Power s service area? Should the costs associated with acquiring green tags be recoverable as a legitimate power purchase expense? The 2006 IRP is the policy instrument that Idaho Power is using to introduce public discussion on the questions surrounding environmental attributes. This discussion is designed to bring these questions to the attention of the public through the Idaho and Oregon regulatory commissions for resolution. Idaho Power believes it should purchase and retain green tags from any renewable resource built or purchased by Idaho Power for the supply of energy to its customers. In addition the acquisition and retention of green tags is necessary to accurately represent the renewable energy component of Idaho Power s resource portfolio. Acquiring and retaining green tags assures Idaho Power s customers it has acquired the energy from renewable resources. Idaho Power intends to acquire the green tags associated with energy generation, power purchases, and exchanges. Should future federal or state law impose renewable energy requirements, Idaho Power will be prepared to satisfy the environmental requirements with the green tags. Any new RFPs involving renewable resources will require green tags be provided to Idaho Power as part of the purchase contract. Idaho Power also will pursue regulatory commission approval to require any new PURP A contracts to provide green tags as part of the standard avoided cost rates or as part of the negotiated PURP A purchased power contract. Idaho Power s Green Power Program will not pursue the purchase of green tags from renewable resources contained in its resource portfolio, as Idaho Power already anticipates acquiring those tags. If green tags in Idaho become available from a resource not contained in Idaho Power s resource portfolio, it may pursue the purchase of those tags for the Green Power Program. Idaho Power believes acquiring green tags is a prudent decision and it intends to seek recovery of the costs associated with purchasing green tags as a purchased power expense through regulatory filings. As an interim step, Idaho Power would also consider selling the green tags on a year-to-year basis until they were required by either its Green Power Program or the adoption of a federal or state renewable requirement. Revenue from any green tag sales would flow through the Power Cost Adjustment (PCA) mechanism. 2006 Integrated Resource Plan Page 7 1. 2006 Integrated Resource Plan Summary Idaho Power Company Emission Offsets Depending on market conditions, it may be possible to purchase emission offsets for less than the cost of the CO2 emission adder used in the IRP analysis ($14 per ton). Some members of the IRP AC have suggested it would be prudent for Idaho Power to hedge the carbon emission risk by purchasing emission offsets today at prices less than the $14 per ton used in the IRP analysis. There are differing opinions among IRPAC members regarding carbon offset purchases. The principal reason cited for not purchasing offsets today is the uncertainty associated with whether or not carbon offsets purchased today will meet future carbon control requirements and regulations. Idaho Power believes it should investigate purchasing options to acquire future carbon offsets. Idaho Power could potentially reduce the large financial exposure of possible carbon taxes for the cost of the option premium. Idaho Power believes it should be able to recover the cost of purchasing emission offset options as well as the cost of any emission offsets purchased. Financial Disincentives for DSM Programs Idaho Power believes financial disincentives for DSM programs should be eliminated. One objective of an effective IRP is to assemble a diversified mix of demand-side and supply-side resources designed to minimize the societal costs of reliably supplying electricity to customers. The regulatory requirement is to treat supply-side and demand-side resources equally in the IRP. Idaho Power is a resource portfolio manager for its customers. Like many utilities, Idaho Power recovers a portion of its fixed costs through the energy charges per kWh. Utilities could use two billing components; a fixed charge representing the capital investment and other fixed costs, and a kWh charge reflecting the variable cost of energy. However, low energy charges would likely encourage consumption. Electric utilities and regulatory commissions use the fixed costs to set the kWh charge high in order to discourage waste. In other words, a part of the cost of every kWh represents the system s fixed charges for existing plant and equipment; the rest of the kWh charge reflects the variable cost of producing that kWh of energy. Idaho Power s rates are set based upon assumptions about annual kWh sales through the regulatory process in a general rate case. Whether actual energy consumption is above or below the initial assumptions defined in the rate case, every reduction in sales from efficiency improvements yields a corresponding reduction in fixed cost recovery to the detriment of the utility shareholder. Electric utilities such as Idaho Power support energy efficiency but the rate structure provides a disincentive for Idaho Power to encourage reduced energy consumption due to the resultant reduction in fixed cost recovery. Idaho Power continues to promote energy efficiency and supports the elimination of all financial disincentives for DSM using a process or mechanism that will allow implementation of effective DSM programs without penalizing its shareholders through reduced fixed-cost recovery. IGCC Technology Risk Idaho Power believes there are significant risks associated with developing an Integrated Gasification Combined Cycle (IGCC) generation resource given the current status of the technology. While there have been significant advances in IGCC technology at the component level, sustained long-term integrated operation in baseload utility service is still in the development stage. At the present time, there are only two operational IGCC projects in the United States. In Idaho Power s opinion, two operational units Page 8 2006 Integrated Resource Plan Idaho Power Company 1. 2006 Integrated Resource Plan Summary do not qualify IGCC as a proven technology. Idaho Power believes IGCC is an important and promising technology that may playa significant role in the utility industry in the near future. The 2006 IRP includes a 250 MW IGCC project in 2017. Idaho Power is interested in participating in the development of IGCC technology, but developing an IGCC project is not a risk that Idaho Power is comfortable taking alone. If a near-term opportunity existed to develop a jointly-owned IGCC project with a number of regional utilities, Idaho Power would consider participating in such a project. Although participation in a regional IGCC project is not specifically identified in the preferred portfolio, Idaho Power anticipates the planning flexibility exists to participate if a suitable opportunity is identified. Adding additional resources early in the planning period, such as a share in a regional IGCC project, may allow the 250 MW of IGCC identified in 2017 to be deferred, allowing Idaho Power and its customers to benefit from continued development and cost reductions in this technology. Asset Ownership Idaho Power can develop and own generation assets, rely on power purchase agreements (PP As) and market purchases to supply the electricity needs of its customers, or use a combination of the two ownership strategies. Idaho Power expects to continue participating in the regional power market and enter into mid-term and long-term PP As. However, when pursuing PP As, Idaho Power must be mindful of imputed debt and its potential impact on Idaho Power s credit rating. In the long run, Idaho Power believes asset ownership results in lower costs for customers due to the capital and rate-of-return advantages inherent in a regulated electric utility. Idaho Power s preference is to own the generation assets necessary to serve its customer load. 2006 Integrated Resource Plan Page 9 1. 2006 Integrated Resource Plan Summary Idaho Power Company Page 1 2006 Integrated Resource Plan Idaho Power Company 2. Idaho Power Company Today 2. IDAHO POWER COMPANY TODAY Customer and Load Growth In 1990, Idaho Power Company had over 290 000 general business customers. Today, Idaho Power serves more than 456 000 general business customers in Idaho and Oregon. Firm peak-hour load has increased from less than 100 MW in 1990 to nearly 3 000 MW in the summers of2002, 2003, and 2005. In July 2006 the peak-hour load reached 3 084 MW, which was a new system peak-hour record. Average firm load has increased from 1 200 aMW in 1990 to 1 660 aMW at the end of 2005. Summaries ofIdaho Power s load and customer data are shown in Table 2-1 and Figure 2- Simple calculations using the data in Table 2- suggest that each new customer adds nearly 6 kW to the peak-hour load and nearly 3 kW to average load. In actuality, residential commercial, and irrigation customers generally contribute more to the peak-hour load, whereas industrial customers contribute more to average load. Industrial customers generally have a more consistent load shape whereas residential commercial, and irrigation customers have a load shape with greater daily and seasonal variation. Table 2-Historical Data (1990-2005) Total Peak Average Nameplate Firm Firm Generation Load Load Year (MW)(MW)(MW)Customers 1990 635 052 205 290,492 1991 635 972 206 296 584 1992 694 164 281 306 292 1993 644 935 274 316,564 1994 661 245 375 329 094 1995 703 224 324 339,450 1996 703 2,437 1 ,438 351 261 1997 728 352 1,457 361 838 1998 738 535 1,491 372,464 1999 738 675 552 383 354 2000 738 765 653 393 095 2001 851 500 576 403 061 2002 912 963 622 414 062 2003 912 944 657 425 599 2004 912 843 671 438 912 2005 085 961 660 456,104 Since 1990, Idaho Power s total nameplate generation has increased by 450 MW to 085 MW. The planned addition of a 170 MW combustion turbine at the Danskin Project in April 2008 will increase Idaho Power s total Highlights Idaho Power had over 456 000 retail customers at the end of 2005. Idaho Power expects to add 11 000-000 retail customers per year through 2025. In July 2006, Idaho Power set a new peak-hour load record of 3,084 MW. Summertime peak-hour loads are expected to increase by 80 MW per year through 2025. Average load is expected to increase by 40 aMW per year through 2025. In 2005, DSM programs resulted in a savings of 41 ,267 MWh of electricity and a reduction in peak-hour loads of 47.5 MW. Idaho Power incurs a capital cost of approximately $5,500 to acquire the generation resources necessary to serve each new residential customer. 2006 Integrated Resource Plan Page 11 2. Idaho Power Company Today Idaho Power Company 3500 Figure 1. Historical Data (1990-2005) 500 000 3000 2500 ~ 2000 ..J ... 5 1500 5i 1000 500 450 000 400 000 350,000 300 000 I!! 250,000 g 200 000 (J 150,000 100 000 000 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002200320042005 Year Total Nameplate Generation Peak Firm Load -Average Firm Load Customers nameplate generation to 3 255 MW. Actual generation is lower than total nameplate generation due to factors such as hydrological conditions, fuel purity, maintenance, and facility degradation. The 450 MW increase in capacity represents enough generation to serve about 000 customers at peak times and represents the average energy requirements of about 160 000 customers. Table 2-2 shows Idaho Power s changes in reported nameplate capacity since 1990. Table 2. Changes in Reported Nameplate Capacity Since 1990 Resource Type Year Milner (addition) ................Hydro 1992 Wood River Turbine (removal) .......................Thermal -50 1993 Swan Falls (upgrade) ........Hydro 1994 1995 Twin Falls (upgrade)..........Hydro 1995 Jim Bridger (upgrade)........Thermal 1997 1998, 2002 Boardman (upgrade) .........Thermal 1997 Valmy (upgrade)................Thermal 2001 Danskin (addition) .............Thermal 2001 Bennett Mountain (addition) Thermal 173 2005 Since 1990, Idaho Power has added more than 165 000 new customers. The simple peak-hour and average energy calculations mentioned earlier suggest the additional 165 000 customers require over 900 MW of additional peak-hour capacity and over 450 aMW of energy. Idaho Power anticipates adding between 11 000 and 12 000 customers each year throughout the planning period. The same simple calculations suggest that peak-hour load requirements are expected to grow at about 80 MW per year and average energy is forecast to grow at about 40 aMW per year. More detailed customer and load forecasts are discussed in Chapter 3 and in Appendix A-Sales and Load Forecast. The simple peak-hour load calculations indicate Idaho Power will need to add peaking capacity equivalent to the 90 MW Danskin plant every year or peaking capacity equivalent to the 173 MW Bennett Mountain plant every two years, throughout the entire planning period. The 10- year and near-term action plans to meet the requirements of the new customers are discussed in Chapters 7 and 8. Page 12 2006 Integrated Resource Plan Idaho Power Company 2. Idaho Power Company Today The generation costs per kW included in Chapter 5 help put the customer growth in perspective. Load research data indicate the average residential customer requires about 1.5 kW ofbaseload generation and 6.5 to 7 kW of peak-hour generation. Baseload generation capital costs are about $2 000 per kW for advanced coal technologies, wind, or geothermal generation, and peak-hour generation capital costs are about $500 per kW for a natural gas combustion turbine. The capital costs do not include fuel or any other operation and maintenance expenses. Based on the capital cost estimates, each new residential customer requires about $3 000 of capital investment for 1.5 kWofbaseload generation, plus $2 500 for an additional 5 kW of peak-hour generation for a total generation capital cost of $5 500. Other capital costs such as transmission costs, distribution costs, and customer systems costs are not included in the 500 capital generation requirement. The forecasted residential customer growth rate of 500 new customers per year translates into over $50 million of new generation plant capital per year to serve new residential customers. Supply-Side Resources Idaho Power has over 3 087 MW of installed or existing generation including 1 379 MW of thermal generation (nameplate capacity). In 2005 , hydroelectric generation supplied 36 percent of the customers' energy needs thermal generation supplied 42 percent, and purchased power supplied the remaining 22 percent of the customers ' energy needs. Idaho Power s supply-side resources are listed in Table 2- In addition to its existing resources, Idaho Power has made a commitment to develop two additional generation resources. In 2005, Idaho Power issued an RFP to acquire an additional peaking resource. The RFP was identified in the 2004 IRP as part of the 10-year action plan. Idaho Power evaluated the submitted bids and selected a 170 MW, simple-cycle, natural gas- fired combustion turbine proposed for the Danskin plant. Idaho Power is presently before the IPUC seeking a Certificate of Public Convenience and Necessity for the Danskin addition which is scheduled to be on-line in 2008. Table 2-3. Supply-Side Resources Resource Type American Falls ..... Hydro Bliss ..................... Hydro Brownlee .............. Hydro Cascade............... Hydro Clear Lake............ Hydro Hells Canyon........ Hydro Lower Malad ........ Hydro Upper Malad ........ Hydro Milner ................... Hydro Oxbow.................. Hydro Shoshone Falls .... Hydro Shoshone Falls (2010).............. Hydro Lower Salmon ...... Hydro Upper Salmon A... Hydro Upper Salmon B... Hydro J. Strike ............ Hydro Swan Falls ........... Hydro Thousand Springs .,.......... Hydro Twin Falls............. Hydro Boardman ............ Thermal Jim Bridger........... Thermal Valmy ................... Thermal Bennett Mountain Thermal Danskin ................ Thermal Danskin (2008)..... Thermal Salmon................. Thermaf 1 Coal 2 Natural Gas 3 Diesel Nameplate Capacity (MW) 585 392 190 771 284 173 170 Location Upper Snake Mid-Snake Hells Canyon N Fork Payette S Central Idaho Hells Canyon S Central Idaho S Central Idaho Upper Snake Hells Canyon Upper Snake Upper Snake Mid-Snake Mid-Snake Mid-Snake Mid-Snake Mid-Snake S Central Idaho Mid-Snake N Central Oregon SW Wyoming N Central Nevada SW Idaho SW Idaho SW Idaho E Idaho Idaho Power has also committed to upgrading the 12.5 MW Shoshone Falls Hydroelectric Project. The project currently has three generator/turbine units with nameplate capacities of 11.5 MW, 0.6 MW, and 0.4 MW. The upgrade project involves replacing the two smaller units with a single 50 MW unit which will result in a net upgrade of 49 MW. The total 2006 Integrated Resource Plan Page 13 2. Idaho Power Company Today Idaho Power Company nameplate capacity of the project will be 61.5 MW when the upgrade is completed in 2010. The Danskin addition and Shoshone Falls upgrade do not appear in the 2006 preferred portfolio because they are considered to be committed resources. Hydro Resources Idaho Power operates 18 hydroelectric generating plants located on the Snake River and its tributaries. Together, these hydroelectric facilities provide a total nameplate capacity of 708 MW and annual generation equal to approximately 970 aMW, or 8.5 million MWh annually under median water conditions. The backbone of Idaho Power s hydroelectric system is the Hells Canyon Complex in the Hells Canyon reach of the Snake River. The Hells Canyon Complex consists of the Brownlee, Oxbow, and Hells Canyon dams and the associated generating facilities. In a normal water year, the three plants provide approximately 67 percent of Idaho Power annual hydroelectric generation, and nearly 40 percent of the total energy generation. The Hells Canyon Complex alone annually generates approximately 5.84 million MWh, or 667 aMW of energy under median water conditions. Water storage in Brownlee Reservoir also enables the Hells Canyon Complex to provide the major portion ofIdaho Power s peaking and load- following capability. Idaho Power s hydroelectric facilities upstream from Hells Canyon include the American Falls Milner, Twin Falls, Shoshone Falls, Clear Lake Thousand Springs, Upper and Lower Malad Upper and Lower Salmon, Bliss, C.J. Strike Swan Falls, and Cascade generating plants. Although the Mid-Snake projects of Upper and Lower Salmon, Bliss, and C.J. Strike, typically follow run-of-river operations, the Lower Salmon, Bliss, and C.J. Strike plants do provide a limited amount of peaking and load-following capability. When possible, the schedules at the plants are adjusted within the FERC license requirements to coincide with the daily system peak demand. All of the other upstream plants are operated as run-of-river projects. Idaho Power has entered into a Settlement Agreement with the U.S. Fish and Wildlife Service that provides for a study of Endangered Species Act (ESA) listed snails and their habitat. The objective of the research study is to determine the impact of load following operations on the Bliss Rapids snail and the Idaho Spring snail. The five-year study requires Idaho Power to operate the Bliss and Lower Salmon facilities under varying operational constraints to facilitate the Idaho Spring snail research. Run-of-river operations during 2003 and 2004 will serve as the baseline, or control for the study. Idaho Power will operate the plants to follow load during the 2005 and 2006 years of the study. General Hells Canyon Complex Operations Idaho Power operates the Hells Canyon Complex to comply with the existing FERC license, as well as voluntary arrangements to accommodate other interests , such as recreational use and environmental resources. Among the arrangements are the fall chinook plan voluntarily adopted by Idaho Power in 1991 to protect spawning and incubation of fall chinook below Hells Canyon Dam. The fall chinook is a species that is listed as threatened under the ESA. Additional voluntary arrangements include the cooperative arrangement that Idaho Power had with federal interests between 1995 and 2001 to implement portions of the Federal Columbia River Power System (FCRPS) biological opinion flow augmentation program. The flow augmentation plan was viewed as a reasonable and prudent alternative under the biological opinion and the intent of the arrangement was to avoid jeopardizing the ESA-listed anadromous species as a result of FCRPS operations below the Hells Canyon Complex. Page 14 2006 Integrated Resource Plan Idaho Power Company 2. Idaho Power Company Today Brownlee Reservoir is the only one of the three Hells Canyon Complex reservoirs-and Idaho Power s only reservoir-with significant active storage. Brownlee Reservoir has 101 vertical feet of active storage capacity, which equals approximately one million acre-feet of water. Both Oxbow and Hells Canyon reservoirs have significantly smaller active storage capacities- approximately 0.5 percent and 1.0 percent of Brownlee Reservoir s volume, respectively. Brownlee Reservoir Seasonal Operations Brownlee Reservoir is a year-round, multiple- use resource for Idaho Power and the Pacific Northwest. Although the primary purpose is to provide a stable power source, Brownlee Reservoir is also used to control flooding, to benefit fish and wildlife resources, and for recreation. Brownlee Dam is one of several Pacific Northwest dams that are coordinated to provide springtime flood control on the lower Columbia River. Between 1995 and 2001 , Brownlee Reservoir, along with several other Pacific Northwest dams, was used to augment flows in the lower Snake River consistent with the FCRPS biological opinion. For flood control Idaho Power operates the reservoir in accordance with flood control directions received from the U.S. Army Corps of Engineers (US Army COE) as outlined in Article 42 of the existing FERC license. After the flood-control requirements have been met in late spring, Idaho Power attempts to refill the reservoir to meet peak summer electricity demands and provide suitable habitat for spawning bass and crappie. The full reservoir also offers optimal recreational opportunities through the Fourth of July holiday. The U.S. Bureau of Reclamation (BOR) periodically releases water from BOR storage reservoirs in the upper Snake River in an effort to augment flows in the lower Snake River to help anadromous fish migrate past the FCRPS projects. The periodic releases are part of the flow-augmentation implemented by the 2000 FCRPS biological opinion. From 1995 through the summer of 2001 , Idaho Power cooperated with the BOR and other interested parties by shaping (or pre-releasing) water from Brownlee Reservoir and occasionally contributing water from Brownlee Reservoir to the flow- augmentation efforts. The pre-released water was later replaced with water released by the BOR from the upper Snake River reservoirs. Recognizing the federal responsibility for the flow-augmentation program, in 1996 the Bonneville Power Administration (BP A) entered into an energy exchange agreement with Idaho Power to facilitate Idaho Power cooperation with the FCRPS flow-augmentation program. The BP A energy exchange agreement expired in April 2001 and even though Idaho Power expressed a willingness to continue to participate in the FCRPS flow-augmentation program through a similar arrangement, BP A chose not to renew the agreement. Although the agreement has expired, Idaho Power continues to support the flow-augmentation program to benefit anadromous fish migration. Brownlee Reservoir s releases are managed to maintain constant flows below Hells Canyon Dam in the fall as a result of the voluntary fall chinook plan adopted by Idaho Power in 1991. The constant flow helps ensure sufficient water levels to protect fall chinook spawning nests, or redds. After the fall chinook spawn, Idaho Power attempts to refill Brownlee Reservoir by the first week of December to meet wintertime peak-hour loads. The fall spawning flows establish the minimum flow below Hells Canyon Dam throughout the winter until the fall chinook fry emerge in the spring. Maintaining constant flows to protect the fall chinook spawning contributes to the need for additional generation resources during the fall months. The fall chinook operations result in 2006 Integrated Resource Plan Page 15 2. Idaho Power Company Today Idaho Power Company lower reservoir elevations in Brownlee Reservoir and the lower reservoir elevations reduce the power production capability of the plant. The reduced power production may cause Idaho Power to have to acquire power from other sources to meet customer load. Federal Energy Regulatory Commission Relicensing Process Idaho Power s hydroelectric facilities, with the exception of the Clear Lake and Thousand Springs plants, operate under licenses issued by the Federal Energy Regulatory Commission (FERC). The process of relicensing Idaho Power s hydroelectric projects at the end of their initial 50-year license periods is well under way as shown in the schedule in Table 2- Table 4. Hydropower Project Relicensing Schedule FERC Nameplate Current File FERC License Capacity License License Project Number (MW)Expires Application Hells Canyon Complex..........1971 167 July 2005 July 2003 Swan Falls...........503 June 2010 June 2008 Bliss.....................1975 Aug. 2034 July 2032 Lower Salmon .....2061 Aug. 2034 July 2032 Upper Salmon A..2777 Aug. 2034 July 2032 Upper Salmon B..2777 Aug. 2034 July 2032 Shoshone Falls...2778 Aug. 2034 July 2032 J. Strike............2055 Aug. 2034 July 2032 Upper/Lower Malad..............2726 March 2035 Feb. 2033 1 Operating under annual renewal of existing license Applications to relicense Idaho Power s three Mid-Snake facilities (Upper Salmon, Lower Salmon, and Bliss) were submitted to FERC in December 1995. The application to relicense the Shoshone Falls Project was filed in May 1997. The application to relicense the C.J. Strike Project was filed in November 1998 and the application to relicense the Malad projects was filed in July 2002. The FERC issued new licenses for Upper Salmon, Lower Salmon Bliss, c.J. Strike, and Shoshone Falls in August 2004 and for the Malad projects in March 2005. The application to relicense the Hells Canyon Complex was filed in July 2003. The relicensing application for the Swan Falls Project will be filed in 2008. Failure to relicense any of the existing hydropower projects at a reasonable cost will create upward pressure on the current electric rates of Idaho Power customers. The relicensing process also has the potential to decrease available capacity and increase the cost of a project's generation through additional operating constraints and requirements for environmental protection, mitigation, and enhancement (PM&E) imposed as a condition for relicensing. A reduction in the operational flexibility ofIdaho Power s hydro system will also negatively impact the ability to integrate wind resources. Idaho Power s goal throughout the relicensing process is to maintain the low cost of generation at the hydroelectric facilities while implementing non-power measures designed to protect and enhance the river environment. No reduction of the available capacity or operational flexibility of the hydroelectric plants to be relicensed has been assumed as part of the 2006 IRP. If capacity reductions or reductions in operational flexibility do occur as a result of the relicensing process, Idaho Power will adjust future resource plans to reflect the need for additional capacity resources in order to maintain the existing level of reliability. Environmental Analysis The National Environmental Policy Act requires that the FERC perform an environmental assessment of each hydropower license application to determine whether federal action will significantly impact the quality of the natural environment. If so, then an environmental impact statement (EIS) must be prepared prior to granting a new license. The FERC has recently issued the draft EIS for the Page 16 2006 Integrated Resource Plan Idaho Power Company Hells Canyon Complex which is currently being reviewed by Idaho Power. The draft EIS was noticed in the Federal Register on August 4 2006, which is the beginning of the 60-day comment period. Opportunity for additional public comment on the draft EIS and final EIS for the Hells Canyon Complex will occur before the license order is issued. Because the project's current license expired before a new license has been issued, an annual operating license is issued by the FERC pending completion of the licensing process. Hydroelectric Relicensing Uncertainties Idaho Power is optimistic that the relicensing process will be completed in a timely fashion. However, prior experience indicates the relicensing process will result in an increase in the costs of generation from the relicensed projects. The increased costs are associated with the requirements imposed on the projects as a condition of relicensing. Because the Hells Canyon Complex relicensing is not complete at this time, Idaho Power cannot reasonably estimate the impact of the relicensing process on the generating capability or operating costs of the relicensed projects. At the time of the 2008 IRP Idaho Power will have better information regarding the power generation impacts of relicensing. Baseload Thermal Resources Jim Bridger Idaho Power owns a one-third share of the Jim Bridger coal-fired plant located near Rock Springs, Wyoming. The plant consists of four nearly identical generating units. Idaho Power one-third share of the nameplate capacity of the Jim Bridger plant currently stands at 771 MW. After adjustment for scheduled maintenance periods, estimated forced outages, de-ratings 2. Idaho Power Company Today and transmission losses, the annual energy- generating capability ofIdaho Power s share of the plant through the 2006-2025 planning period is approximately 575 aMW. Pacifi~orp has two-thirds ownership and is the operatIng partner of the Jim Bridger facility. Valmy Idaho Power owns a 50 percent share, or 284 MW, of the 568 MW (nameplate) Valmy coal-fired plant located east ofWinnemucca Nevada. The plant is owned jointly with Sierra Pacific Power Company which performs operation and maintenance services. After adjustment for scheduled maintenance periods estimated forced outages, de-ratings, and transmission losses, the annual energy- generating capability of Idaho Power s share of the Valmy plant through the 2006-2025 planning period is approximately 230 aMW. Boardman Idaho Power owns a 10 percent share, or 56 MW, of the 560 MW (nameplate) coal-fired plant near Boardman, Oregon, operated by Portland General Electric Company. After adjustment for scheduled maintenance periods estimated forced outages , de-ratings, and transmission losses, the annual energy- generating capability of Idaho Power s share of the Boardman plant through the 2006-2025 planning period is approximately 52 aMW. Peaking Thermal Resources Danskin Idaho Power owns and operates the Danskin plant, a 90 MW natural gas-fired project. The plant consists of two 45 MW Sieme~s- Westinghouse W251 B 12A combustIOn turbInes. The 12-acre facility, constructed during the summer of 200 1 , is located northwest of Mountain Home, Idaho. The Danskin plant operates as needed to support system load. 2006 Integrated Resource Plan Page 17 2. Idaho Power Company Today Idaho Power Company Bennett Mountain Idaho Power owns and operates the Bennett Mountain plant, a 173 MW Siemens- Westinghouse 50 IF simple cycle, natural gas-fired combustion turbine located near the Danskin plant in Mountain Home, Idaho. The Bennett Mountain plant operates as needed to support system load. Salmon Diesel Idaho Power owns and operates two diesel generation units located at Salmon, Idaho. The Salmon units have a combined nameplate rating of 5 MW and are primarily operated during emergency conditions. Public Utility Regulatory Policies Act In 1978 the United States Congress passed the Public Utility Regulatory Policies Act requiring electric utilities such as Idaho Power to purchase the energy from Qualifying Facilities (QF). Qualifying Facilities are small privately-owned, renewable generation projects or small cogeneration projects. The individual states were given the task of establishing the terms and conditions, including price, that each state s utilities are required to pay as part of the PURP A agreements. Idaho Power operates in Idaho and Oregon and has a different set of contract requirements for PURP A projects for each state jurisdiction. Idaho Projects The IPUC has established two classes of PURP A projects: 1. Non-firm projects: Non-firm contracts are for project operators who have no desire to commit to a contract term or commit to any quantity of energy deliveries. A non- firm agreement contains pricing based on the monthly market value of energy for each month when the project delivers energy to Idaho Power. 2. Firm projects: Firm contracts are for project operators who are willing to make a commitment on both the contract term and the specific levels of energy delivery. As specified by various IPUC orders: Term of the agreements cannot exceed 20 years. Projects that deliver 10 aMW or less measured on a monthly energy delivery basis, are eligible for the IPUC Published Avoided Cost. Projects that deliver greater than 10 aMW, measured on a monthly energy delivery basis , will receive negotiated energy prices based upon Idaho Power IRP energy pricing models and the specific delivery characteristics of the generation project. The Idaho PURP A Published Avoided Cost model is designed to estimate the cost of an additional utility resource that will be avoided by the addition of the PURPA project. The current Idaho PURPA avoided cost model assumes that a natural gas combined-cycle turbine is the surrogate avoided resource that Idaho utilities avoid through the addition of PURP A resources. Idaho Power has not selected a natural gas combined-cycle plant in the preferred resource portfolio since the 2000 IRP. Idaho Power may propose using a different type of resource for the surrogate avoided resource to determine published avoided costs in a future regulatory proceeding. The Idaho PURP A avoided-cost model requires forecast inputs, including expected plant life estimated plant cost, expected year of plant construction, estimated fixed O&M costs estimated variable O&M costs, estimated cost escalation rates, estimated fuel cost and the associated fuel cost escalation rate, and assumed Page 18 2006 Integrated Resource Plan Idaho Power Company 2. Idaho Power Company Today plant design characteristics such as the plant heat rate. Of the inputs, fuel cost and the associated fuel cost escalation rate have the greatest influence on the resulting PURP A energy pnce. In IPUC Order 29124, the IPUC adopted the Northwest Power and Conservation Council' (NWPCC) median natural gas price forecast for the fuel cost input. The IPUC updates the PURP A Published Avoided Cost whenever new forecasts from the NWPCC are published. The most recent NWPCC natural gas price forecast was incorporated in IPUC Order 29646 dated December 1 , 2004, which established the Idaho Power PURP A Published Avoided Cost to be 60.99 Mills per kWh (levelized rate generation plant on-line in 2006, and 20-year contract term). Oregon Projects The OPUC, the utilities serving Oregon, and other interested parties are currently in the process of revising the processes, terms and conditions for PURP A projects located in the State of Oregon. At this time, Oregon Schedule 85 requires Idaho Power to purchase energy from PURP A projects with less than 10 MW of nameplate generation. As specified by Oregon Schedule 85: The contract must follow the standard PURP A agreement on file with the OPUC Term of the agreement cannot exceed 20 years There are three pricing options under Oregon Schedule 85: 1. Fixed Price Option: The energy price is fixed for all energy deliveries. The fixed-price option is very comparable to the IPUC Published A voided Costs method. 2. Deadband Option: The deadband option contains a fixed-price component plus a variable-price component that is based on monthly natural gas prices. The calculated gas price is then confined between a cap and floor creating the deadband. " 3. Gas Index Option: The gas price option contains a fixed-price component plus a variable-price component that is based on monthly natural gas prices. The current Schedule 85 proceeding at the OPUC is addressing the PURPA terms and conditions for projects with a nameplate rating greater than 10 MW. Cogeneration and Small Power Producers (CSPP) Idaho Power has over 90 contracts with independent power producers for over 400 MW of nameplate capacity. The CSPP generation facilities consist of low-head hydro projects on various irrigation canals, cogeneration projects at industrial facilities, and various small renewable power projects. Idaho Power is required to take the energy from the projects as the energy is generated and it cannot dispatch the CSPP projects. PURP A and various Idaho and Oregon PUC orders govern the rules, rates and requirements for independent power producers. Purchased Power Idaho Power relies on regional markets to supply a significant portion of energy and capacity. Idaho Power is especially dependent on the regional markets during peak periods. Reliance on regional markets has benefited Idaho Power customers during times of low prices as the costs of purchases, the revenue from surplus sales, and fuel expenses are shared with customers through the PCA. However, the reliance on regional markets can be costly in times of high prices such as during the summer 2006 Integrated Resource Plan Page 19 2. Idaho Power Company Today Idaho Power Company of 200 1. As part of the 2002 IRP process, the public, the IPUC, and the Idaho Legislature all suggested that the time had come for Idaho Power to reduce the reliance on regional market purchases. Greater planning reserve margins or the use of more conservative water planning criteria were suggested as methods requiring Idaho Power to acquire more firm resources and reduce its reliance on market purchases. Idaho Power adopted more conservative water planning criteria in the 2002 IRP and has continued utilizing the more conservative water planning criteria in the 2004 and 2006 Integrated Resource Plans. Figure 2-2 shows the percentages of Idaho Power s energy resources to serve customer load in 2005. As recently as 1998, the proportion of hydro generation exceeded 50 percent and purchased power was only 15 percent of the resource portfolio. Customer growth combined with below normal water lowered the proportion of hydro to 36 percent and increased purchased power to 22 percent of the portfolio in 2005. Figure 2. 2005 Energy Sources Transmission Interconnections Description The Idaho Power transmission system is a key element serving the needs of Idaho Power retail customers. The 345 kV, 230 kV, and 138 kV main grid system is essential for the delivery of bulk power supply. Figure 2-3 shows the principal grid elements ofIdaho Power high-voltage transmission system. Capacity and Constraints Idaho Power s transmission connections with regional utilities provide paths over which off-system purchases and sales are made. The transmission interconnections and the associated power transfer capacities are identified in Table 2-5. The capacity of a transmission path may be less than the sum of the individual circuit capacities. The difference is due to a number of factors, including load distribution potential outage impacts, and surrounding system limitations. In addition to the restrictions on interconnection capacities, other internal transmission constraints may limit Idaho Power s ability to access specific energy markets. The internal transmission paths needed to import resources from other utilities and their respective potential constraints are also shown in Figure 2-3 and Table 2- Brownlee-East Path The Brownlee-East transmission path is on the east side of the Northwest Interconnection shown in Table 2-5. Brownlee-East is comprised of the 230 kV and 138 kV lines east of the Brownlee/Oxbow/Quartz area. When the Midpoint-Summer Lake 500 kV line is included with the Brownlee-East path, the path is typically referred to as the Brownlee-East Total path. The constraint on the Brownlee-East transmission path is within Idaho Power s main transmission grid and located in the area between Brownlee and Boise on the west side of the system. The Brownlee-East path is most likely to face summer constraints during normal to high water years. The constraints result from a combination of Hells Canyon Complex hydro generation flowing east into the Treasure Valley, concurrent with transmission wheeling obligations and purchases from the Pacific Page 20 2006 Integrated Resource Plan Idaho Power Company 2. Idaho Power Company Today i:; ~ i ~ :J: :;::. w,,- I I- 00( :;.- "'" z+~ V'J 11) (/)!!! 11) ... ('II ... i.i: c:S: d~ ; ~ ! :I: I~", 2006 Integrated Resource Plan Page 21 2. Idaho Power Company Today Idaho Power Company Table 2-5. Transmission Interconnections Transmission Interconnections Connects Idaho Power To Northwest Capacity To Idaho From Idaho 090 to 1 200 MW 2,400 Line or Transformer Oxbow-Lolo 230 kV Avista Midpoint-Summer Lake 500 kV PacifiCorp (PPL Division) Hells Canyon-Enterprise 230 kV PacifiCorp (PPL Division) Quartz Tap-LaGrande 230 kV BPA Hines-Harney 138/115 kV BPA Sierra 262 MW 500 MW Midpoint-Humboldt 345 kV Sierra Pacific Power Eastern Idaho Kinport-Goshen 345 kV PacifiCorp (PPL Division) Bridger-Goshen 345 kV PacifiCorp (PPL Division) Brady-Antelope 230 kV PacifiCorp (PPL Division) Blackfoot-Goshen 161 kV PacifiCorp (PPL Division) Utah (Path C)775 to 950 MW 830 to 870 MW Borah-Ben Lomond 345 kV PacifiCorp (PPL Division) Brady- Treasureton 230 kV PacifiCorp (PPL Division) American Falls-Malad 138 kV PacifiCorp (PPL Division) Montana 79MW 79MW Antelope-Anaconda 230 kV NorthWestern Energy 87MW 87MW Jefferson-Dillon 161 kV NorthWestern Energy Pacific (Wyoming)600 MW 600 MW Jim Bridger 345/230 kV PacifiCorp (Wyoming Division) Power Transfer Capacity for Idaho Power s Interconnections 1 The Idaho Power-PacifiCorp interconnection total capacities in eastern Idaho and Utah include Jim Bridger resource integration. 2 The Path C transmission path also includes the internal PacifiCorp Goshone-Grace 161 kV line. 3 The direct Idaho Power-Montana Power schedule is through the Brady-Antelope 230 kV line and through the Blackfoot-Goshen 161 kV line that are listed as an interconnection with PacifiCorp. As a result, Idaho-Montana and Idaho-Utah capacities are not independent. Northwest. Transmission wheeling obligations also affect southeastern flow into and through southern Idaho. Significant congestion affecting southeast energy transmission flow from the Pacific Northwest may also occur during the month of December. Restrictions on the Brownlee-East path limit the amount of energy Idaho Power can import from the Hells Canyon Complex, as well as off-system purchases from the Pacific Northwest. The Brownlee-East Total constraint is the primary restriction on imports of energy from the Pacific Northwest during normal and high water years. If new resources are sited west of this constraint, additional transmission capacity will be required to remove the existing Brownlee-East transmission constraint to deliver the energy from the additional resources to the Boise/Treasure Valley load area. Oxbow-North Path The Oxbow-North path is a part of the Northwest Interconnection and consists of the Hells Canyon-Brownlee and Lolo-Oxbow 230 kV double-circuit line. The Oxbow-North path is most likely to face constraints during the summer months when high northwest-to- southeast energy flows and high hydro production levels coincide. Congestion on the Oxbow-North path also occurs during the winter months of November and December due to winter peak conditions throughout the region. Northwest Path The Northwest path consists of the 500 kV Midpoint-Summer Lake line, the three 230 kV lines between the Northwest and Brownlee, and the 115 kV interconnection at Harney. Deliveries of purchased power from the Pacific Northwest flow over these lines. During peak Page 22 2006 Integrated Resource Plan Idaho Power Company 2. Idaho Power Company Today summer periods, total purchased power needs may exceed the capability of the Northwest Path. If new resources are sited west of this constraint, additional transmission capability will be needed to transmit the energy into Idaho Power s control area. Borah-West Path The Borah-West transmission path is within Idaho Power s main grid transmission system located west of the eastern Idaho, Utah Path C Montana and Pacific (Wyoming) intercon- nections shown in Table 2-5. The Borah-West path consists ofthe 345 kV and 138 kV lines west of the BorahiBrady/Kinport area. The Borah-West path will be of increasing concern because its capacity is fully utilized by existing wheeling obligations. There is a strong probability that many of the generation alternatives considered in the 2006 IRP will be sited east of the Borah-West transmission path. Transmission improvements on the Borah-West transmission path will be required to transfer energy from any new generation sited on the east side of Idaho Power s service area to serve load growth in the Boise area. Idaho Power is presently upgrading the capacity of the Borah-West path. The transmission improvements identified in the 2004 IRP will increase the Borah-West transmission capacity by 250 MW and are expected to be completed in May 2007. The increased transmission capacity will be available to serve Idaho Power s native load requirements with new generating resources located east of the Borah-West constraint. Midpoint-West Path The Midpoint-West path is another transmission constraint that exists just west of the Midpoint area. The Midpoint-West constraint is slightly less restrictive than the Borah-West constraint at the present time. Relatively small improvements on the Borah- West constraint may result in the Midpoint- West constraint limiting east-to-west transfers. Any significant improvement in the east-to-west transfers will more than likely require considerable upgrades to both the Borah-West and Midpoint-West paths. The addition of a new combustion turbine at the Danskin site near Mountain Home, Idaho will necessitate transmission improvements to the Midpoint- West path. The most significant improvements are the addition of two new 230 kV transmission lines; one in the area around Mountain Home Idaho from the Bennett Mountain 173 MW combustion turbine to the combustion turbines at the Danskin site north of Mountain Home and the other 230 kV line from the Danskin site to the Mora Substation near Boise. Regional Transmission Organizations In 1999, the FERC issued Order 2000 to encourage voluntary membership in regional transmission organizations (RTOs). FERC Order 2000 precipitated considerable activity within the Pacific Northwest focused on the decisions about whether to create an RTO and how it should operate. To date, the effort to form an R TO in the Pacific Northwest has been unsuccessful. Idaho Power will continue to be an active participant in efforts to determine an appropriate structure for provision of transmission service within the Pacific Northwest. Off-System Purchases, Sales, and Load-Following Agreements Idaho Power currently has two, fixed-term off-system sales contracts. The contracts expiration dates, and average sales amounts are shown in Table 3-3 in Chapter 3. The City of Weiser, Idaho has a full- requirements, fixed-term sales contract with Idaho Power. Under the full-requirements contract, Idaho Power is responsible for 2006 Integrated Resource Plan Page 23 2. Idaho Power Company Today Idaho Power Company supplying the entire load of the city. The City of Weiser is located entirely within Idaho Power load-control area. A fixed-term sales contract with Raft River Rural Electric Cooperative was established as a full-requirements contract after being approved by the FERC and the Public Utilities Commission of Nevada. The Raft River Cooperative is the electric distribution utility serving Idaho Power s former customers in Nevada. On April 2, 2001 , Idaho Power sold the transmission and distribution facilities, along with the rights-of-way that serve approximately 250 customers in northern Nevada and 90 customers in southern Owyhee County, Idaho to the Raft River Cooperative. The area sold is located entirely within Idaho Power load-control area. Idaho Power and Montana s NorthWestern Energy have negotiated a load-following agreement in which Idaho Power provides NorthWestern Energy with 30 MW of load-following service. The agreement includes provisions allowing Idaho Power to receive energy from NorthWestern Energy on the east side of the system during summer months. Renewal of the load-following agreement with NorthWestern Energy will depend on a number of factors , including the amount of wind generation on Idaho Power s system. Idaho Power also has a load-following agreement with NorthWestern for serving its load in Salmon Idaho, which is located in NorthWestern s load control area. Both agreements are automatically renewed each year with the consent of Idaho Power and NorthWestern Energy. Demand-Side Management Idaho Power includes DSM programs along with supply-side resources and transmission interconnections in the IRP resource stack. Idaho Power develops and implements demand- side programs to help manage energy demand. The two primary objectives of the DSM programs are to: 1. Acquire cost-effective resources in order to more efficiently meet the electrical systems needs; and 2. Provide Idaho Power customers with programs and information to help them manage their energy use and lower their bills. Idaho Power achieves the two objectives through the development and implementation of programs with specific energy, economic, and customer objectives. Under the DSM umbrella the programs fall into four categories: Demand Response, Energy Efficiency, Market Trans- formation, and Other Programs and Activities. During 2005, the IPUC approved Idaho Power request to increase the Rider from 0.5 to 1. of base rate revenues (Case No. IPC-04-29). The funding increase became effective on June 1 2005. In July 2005 , Idaho Power filed a request with the OPUC to implement a Rider in its Oregon service area. The Oregon Rider is identical to the Rider approved in Idaho. The OPUC approved the Oregon Rider in August 2005 (Advice No. 05-03). Idaho Power relies on the input from the EEAG to provide customer and public interest review ofDSM programs. Formed in 2002 and meeting several times annually, the EEAG currently consists of 12 members representing a cross-section of customer segments including residential, industrial, commercial, irrigation elderly, low-income, and environmental interests as well as members representing the Public Utility Commissions of Idaho and Oregon and Idaho Power. In addition to the EEAG, Idaho Power solicits further customer input through stakeholder groups in the industrial, irrigation, and commercial customer segments. Page 24 2006 Integrated Resource Plan Idaho Power Company 2. Idaho Power Company Today In 2005, Idaho Power agreed to a renewal agreement funding the Northwest Energy Efficiency Alliance (Alliance) for five years (2005-2009). The Alliance s efforts in the Pacific Northwest affect Idaho Power customers through the regional market transformation efforts as well as providing structural support for Idaho Power s local market transformation programs. Idaho Power continues to leverage the support provided by the Alliance in the development and marketing of local programs, resulting in efficiencies of program implementation. In October 2005, Idaho Power began its fifth year of a five-year agreement with the BP A through the Conservation and Renewable Discount (C&RD) program. Idaho Power operates several programs with the C&RD funding including Energy House Calls and Rebate Advantage. The BP A has introduced a replacement program called the Conservation Rate Credit (CRC) program available from 2007-2009 and Idaho Power will be eligible for early participation. Overview of Program Performance In 2005, DSM programs at Idaho Power continued to grow and to show steady improvement in customer satisfaction. The six programs identified for implementation in the 2004 IRP were in place and operating by the end of2005. The two Demand Response programs-Irrigation Peak Rewards and A/C Cool Credit-resulted in a reduction of summertime peak-hour load of over 43 MW. The four Energy Efficiency programs- Industrial Efficiency, Commercial Building Efficiency, ENERGY STARcw Homes Northwest, and Irrigation Efficiency Rewards- resulted in an annual savings of 13 946 MWh. In addition to the DSM programs identified in the 2004 IRP, during 2005 Idaho Power operated several other Energy Efficiency programs targeting residential customers including: Weatherization Assistance for Qualified Customers (previously known as Low Income Weatherization Assistance program, or LIW A), Energy House Calls, Rebate Advantage, and Oregon Residential Weatherization. In 2005 , Idaho Power also joined the regional Savings with a Twist program sponsored by BP A. This program provides Idaho Power customers with low-priced compact fluorescent light (CFL) bulbs in local retail stores. These five residential energy-efficiency programs created a savings of 756 MWh in 2005. Idaho Power continues to realize significant Market Transformation benefits through Idaho Power s partnership with the Alliance, which estimates 20 054 MWh were saved in Idaho Power s service area in 2005. Idaho Power also participated in small demonstration projects and educational opportunities with an estimated savings of 512 MWh in 2005. Table 2-6 shows the 2005 annual energy savings and summer peak reduction associated with each of the DSM program categories. The energy savings totaled 41 267.5 MWh and the estimated peak reduction was 47.5 MW during the 2005 summer peak. All energy statistics presented in this report are net of transmission line losses unless otherwise noted. Table 6. 2005 DSM Energy and Peak Impact MWh Peak MW 43. 2.4 Demand Response ....................... Energy Efficiency.......................... Market Transformation .................. Other Programs and Activities....... Total 2005 1 Based on annual aMW 701. 20,053. 512. 41,267.47. 2006 Integrated Resource Plan Page 25 2. Idaho Power Company Today Idaho Power Company Page 26 2006 Integrated Resource Plan Idaho Power Company 3. PLANNING PERIOD FORECASTS 3. Planning Period Forecasts Table 3-Load Forecast Probability Boundaries (aMW) Growth Forecast Low Expected High Year Load Load Load 2005 (Actual)693 693 693 2006 710 1,7 46 783 2007 737 786 843 2008 763 822 895 2009 788 857 943 2010 816 892 993 2011 834 918 031 2012 851 942 067 2013 880 978 115 2014 909 014 163 2015 937 051 210 2016 967 089 258 2017 996 128 306 2018 027 167 355 2019 058 207 2,405 2020 090 248 2,456 2021 123 290 508 2022 157 333 561 2023 191 376 614 2024 226 2,419 669 2025 261 2,464 724 Growth Rate (2005-2025)2.4% Table 3-2 summarizes three forecasts that represent Idaho Power s estimate of its annual total load growth over the planning period considering normal, 70th percentile and 90th Load Forecast Future demand for electricity by customers in Idaho Power s service area is defined by a series of six load forecasts, reflecting a range of load uncertainty resulting from differing economic growth and weather-related assumptions. Table 3-1 summarizes three forecasts that represent Idaho Power s estimate of the boundaries of its annual total load growth over the planning period considering economic and demographic impacts on the load forecast (normal weather is assumed). There is a 90 percent probability that Idaho Power s load growth will exceed the Low Load Growth Forecast, a 50 percent probability ofload growth exceeding the Expected Load Growth Forecast, and a 10 percent probability that load growth will exceed the High Load Growth Forecast. The projected 20-year average annual compound growth rate in the expected load forecast is 1.9 percent. Idaho Power believes the Expected Load Growth Forecast is the most likely forecast and uses this forecast as the basis for further analysis of weather-related uncertainties presented in Table 3- Highlights Idaho Power s average load is expected to grow at a rate of 1.9% annually throughout the planning period. The number of residential customers in Idaho Power s service area is expected to increase from around 381 000 at the end of 2005 to nearly 571 000 by the end of the planning period in 2025. Based on recent history, Snake River streamflows are expected to continue to decline by approximately 53 cfs per year which results in a loss of hydroelectric generation of 25-30 aMW annually. Hydrologic conditions were worse than the 90th percentile in 2001 and worse than the 70th percentile from 2001-2005. 2006 Integrated Resource Plan Page 27 3. Planning Period Forecasts Idaho Power Company percentile weather impacts (explained in more detail below) on the Expected Load Growth Forecast shown in Table 3-1. Idaho Power uses the 70th percentile forecast as the basis for resource planning. The 70th percentile forecast is based on 70th percentile weather to forecast average monthly load, 70th percentile water to forecast hydro generation, and 95th percentile monthly weather to forecast monthly peak-hour load. The 70th percentile forecast is referenced throughout the Integrated Resource Plan. Table 2. Range of Total Load Growth Forecasts (aMW) Year Median Percentile Percentile 2005 (Actual)693 693 693 2006 746 786 855 2007 786 827 897 2008 822 864 935 2009 857 899 972 2010 892 935 008 2011 918 961 036 2012 942 986 061 2013 978 023 099 2014 014 059 136 2015 051 097 175 2016 089 135 213 2017 128 174 254 2018 167 214 294 2019 207 255 336 2020 248 295 377 2021 290 338 2,421 2022 333 381 2,465 2023 376 2,425 510 2024 2,419 2,469 555 2025 2,464 515 601 Growth Rate (2005-2025) Expected Load Forecast- Economic Impacts The expected load forecast represents the most probable projection of service area load growth during the planning period. The forecast for total load growth is determined by summing the load forecasts for individual classes of service as described in Appendix A-Sales and Load Forecast. For example, the expected total load growth of 1.9 percent is comprised of residential load growth of 1.8 percent, commercial load growth of 2.5 percent, no growth in the irrigation sector, industrial load growth of 2. percent, and additional firm load growth of 1. percent. Economic growth assumptions influence the individual customer-class forecasts. The number of service area households and various employment projections, along with customer consumption patterns, are used to form load projections. Economic growth information for Idaho and its counties can be found in Appendix C-Economic Forecast. The number of households in Idaho is projected to grow at an annual average rate of 1.7 percent during the 20-year forecast period. Growth in the number of households within individual counties in Idaho Power s service area differs from statewide household growth patterns. Service area household projections are derived from individual county household forecasts. Growth in the number of households within the Idaho Power service area, combined with estimated consumption per household, results in the previously mentioned 1.8 percent residential load growth rate. The number of residential customers in Idaho Power s service area is expected to increase 2.0 percent annually from around 381 000 at the end of2005 to nearly 571 000 by the end of the planning period in 2025. Expected Load Forecast- Weather Impacts The expected case load forecast assumes median temperatures and median precipitation meaning there is a 50 percent chance that loads will be higher or lower than the expected case load forecast due to colder-than-median or hotter- than-median temperatures and wetter-than- median or drier-than-median precipitation. Since actual customer loads can vary significantly depending upon weather conditions, two alternative scenarios are Page 28 2006 Integrated Resource Plan Idaho Power Company 3. Planning Period Forecasts analyzed to address load variability due to weather. Idaho Power has generated load forecasts for 70th percentile weather and 90th percentile weather. Seventieth percentile weather means that in seven out of 10 years, the load is expected to be less than the forecast and in three out of 10 years, the load is expected to exceed the forecast. Ninetieth percentile load has a similar definition. Cold winter days create high heating load. Hot dry summers create both high cooling and irrigation loads. Heating degree-days (HDD), cooling degree-days (CD D), and growing degree-days (GDD) are used to quantify the weather and estimate a load forecast. In the winter, maximum load occurs with the highest recorded levels ofHDD. In the summer maximum load occurs with the highest recorded levels ofCDD and GDD. These concepts are further explained in Appendix A-Sales and Load Forecast. For example, according to the Boise Weather Service, the median number ofHDD in December over the 1948-2005 time period is 040 HDD. The coldest December over the same time period was December 1985 when there were 1 619 HDD recorded by the Boise Weather Service. For December, the 70th percentile HDD is 069 HDD. The 70th percentile value is likely to be exceeded in three out of 10 years on average. The 90th percentile HDD is 1 185 HDD and is likely to be exceeded in one out of 10 years on average. Forecast load percentile calculations were used in each month throughout the year for the weather-sensitive customer classes which include residential commercial, and irrigation customers. The 70th percentile is used to forecast average monthly load for energy calculations, and the 95 percentile is used to forecast monthly peak-hour load for generation and transmission capacity calculations. In the 70th percentile residential and commercial load forecasts, temperatures in each month were assumed to be at the 70th percentile of HDD in winter and at the 70th percentile of CDD in the summer. In the 70th percentile irrigation load forecast, GDD were assumed at the 70th percentile and precipitation was assumed to be at the 70th percentile, reflecting weather that is both hotter and drier than median weather. The 90th percentile irrigation load forecast was similarly constructed using weather values measured at the 90th percentile. Idaho Power s total load is highly dependent upon weather. The three scenarios allow careful examination of load variability and how the load variability may impact resource requirements. It is important to understand the probabilities associated with the load forecasts apply to any given month and an extreme month may not necessarily be followed by another extreme month. In fact, a typical year likely contains some extreme months as well as some mild months. Weather conditions are the primary factor affecting the load forecast on the hourly, daily, weekly, monthly, and seasonal time horizon. Economic and demographic conditions affect the load forecast over the long-term horizon. Micron Technology Micron Technology is currently Idaho Power largest individual customer. In the 2006 IRP 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. Presently, Micron s load is approaching 80 aMW. 2006 Integrated Resource Plan Page 29 3. Planning Period Forecasts Idaho Power Company Idaho National Laboratory The Idaho National Laboratory (INL) is a U. Department of Energy (DOE) research facility located in eastern Idaho. The INL is operated for the DOE by Battelle Energy Alliance, LLC which includes the Battelle Memorial Institute teamed with several institutions including BWXT Services Inc., Washington Group International, the Electric Power Research Institute, and the Massachusetts Institute of Technology. The laboratory employs about 000 people. Historically, INL has operated several experimental nuclear reactors and generated a significant portion of its energy needs. Today, the laboratory is a special contract customer of Idaho Power with an average load of around 20 aMW and a peak-hour demand of nearly 40 MW. Simplot Fertilizer The Simplot fertilizer plant is the largest producer of phosphate fertilizer in the western United States. In August 2002, Simp lot closed the ammonia production facility and the ammonia is now purchased from an outside suppler. Electricity usage at the Simplot facility is expected to increase at a very slow rate of growth in the future. Employment in the Chemical and Allied Products sector is the primary indicator used to forecast the use of electricity at the Simplot fertilizer plant. Firm Sales Contracts Idaho Power currently has two firm sales contracts. The contracts, expiration dates, and 2006 average load are shown in Table 3- The contract with Raft River Rural Electric Cooperative expires on September 30 2006. However, the Raft River Cooperative 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 Idaho Power will continue to serve the Raft River Cooperative contract over the entire planning period (2006-2025). However, the 2008 IRP will assume the contract is not extended beyond September 30 2011. Idaho Power anticipates that the contract with the City of Weiser will not be renewed and is, therefore not included in the forecast period after 2006. Table 3-3. Firm Sales Contracts Contract 2006 Average Expiration Load City of Weiser (Idaho) .............. Dec. 31 2006 6 aMW Raft River Rural Electric Cooperative (Nevada) .......... Sept. 30, 2006 6 aMWTotal Firm Sales 12 aMW Idaho Power will continue to evaluate the value of firm sales contracts in the future. With the exception of the Raft River Cooperative contract, Idaho Power has not included the renewal of any term off-system sales contracts in its load forecast. Hydro Forecast The representative hydrologic conditions used for analysis in the 2006 IRP (the 50th, 70th, and 90th percentiles) are based on a computed hydrologic record for the Snake River Basin from 1928-2002. The historical record has been developed by the Idaho Department of Water Resources (IDWR) for the purpose of obtaining a hydrologic period of record of sufficient length to validate probability-based decisions. For example, a median (50th percentile) hydrologic condition based on a 75-year hydrologic period of record is generally considered more representative of true median conditions than the condition derived from a 50-year period of record. Table 3-4 shows the April through July Brownlee inflow history since 1993. The data reported in Table 3- indicate in six of the recent years the Brownleeth inflows were at or below the 70 percentl e planning criterion, and in two of those years 1994 and 2001 , the flows were at or below the 90th percentile planning criterion. Page 30 2006 Integrated Resource Plan Idaho Power Company Table 3.Recent Brownlee Inflow History Worse Worse April-July than 70 than 90 Brownlee Percentile Percentile Inflow Planning Planning Year (MAF)Rank Criterion Criterion 1993 1994 1995 1996 8.4 1997 1998 1999 2000 4.4 2001 2.4 2002 2003 2004 2005 Water management facilities, irrigation facilities, and operations in the Snake River Basin changed greatly during the 20th Century. Therefore, for a hydrologic record to be meaningful from a planning perspective, the hydrologic record should reflect the current level of development in the Snake River Basin. The process followed by IDWR in developing the hydrologic record involves modifying the actual historical record to account for development, present baseflow, current system operations, and existing facilities. For example prior to the late 1940s, the primary irrigation method used was flood irrigation. Since the early 1900s, the construction of storage reservoirs and canal systems in southern Idaho has led to less water in the Snake River. Over the past 50 years, there has also been a significant conversion from flood to sprinkler irrigation, and from surface-supplied irrigation to groundwater-supplied irrigation. There has also been a significant additional amount of groundwater-irrigated land put into production over the past 50 years resulting in reduced spring-fed contributions to the river. As a result of these changes over the years, the natural flow hydro graph has been altered. The timing and volume of the natural flow, in the river and from the springs, has changed. The changes are built 3. Planning Period Forecasts into IDWR's standardized hydrologic record (1928-2002), which is produced by IDWR' depleted flow model, to reflect today s system. Idaho Power uses the IDWR standardized hydrologic record, plus actual flows for 2003 and 2004, in the hydro generation modeling performed for its Integrated Resource Plan. Part of the process by which the historical record is standardized involves adjusting the actual flows to a level of base flow that is representative of the conditions existing today. Baseflow is defined as that portion of streamflow derived primarily from groundwater seepage into the stream channel. Observed records suggest that baseflow in the Snake River, particularly between Idaho Power s Twin Falls and Swan Falls projects, has been declining for several decades. The yearly average flow measured below Swan Falls has declined at an average rate of 53 cubic feet per second (cfs) per year from 1960-2005. In addition, observed streamflow gains between Twin Falls and Lower Salmon Falls, which are largely attributed to baseflow contribution, have declined at a rate of 29 cis/year over the same period. A decrease of 53 cis per year represents the loss of over 38 400 acre-feet of water per year, and a hydro generation loss of approximately 153 aMW in 2005 as compared to 1960. If the trend continues, the reduction in hydro generation due to declining baseflow may reach 183 aMW by 2015. The observed decline, which continues today, is due to consumptive groundwater withdrawals and has been exacerbated by recent drought conditions. Since the 2004 IRP, IDWR has updated its standardized hydrologic record to reflect the present condition of the Snake River Basin as based on data through September 2002. The previous version of the hydrologic record used for the 2004 IRP assumed a present condition as based on data through September 1992. The updated record more accurately reflects the decreased baseflow in the river 2006 Integrated Resource Plan Page 31 3. Planning Period Forecasts Idaho Power Company system. As an example, the assumed annual average streamflow gain between Twin Falls and Lower Salmon Falls for the period 1928-1992 was 5 260 cfs in the previously used IDWR hydrologic record, and is only 4 790 cis in the newly updated version. The results mean that the present condition assumed by IDWR for the Twin Falls to Lower Salmon Falls reach gain, which is largely attributed to baseflow contribution, has declined on an annual average basis by approximately 470 cfs because of changes in basin hydrology observed from 1992-2002. The 470 cfs decline translates to a hydro generation loss of 25-30 aMW on an annual basis. In large part because of the changing nature of the Snake River Basin hydrologic characteristics, IDWR has expressed its intent to update the standardized record more frequently in the future. The updates will be critical in ensuring that the standardized record continues to reflect present Snake River Basin conditions, and the hydro generation levels computed under the various hydrologic conditions are consistent with the associated probabilities assumed in Idaho Power Integrated Resource Plans. Generation Forecast The generation forecast includes existing and committed resources. The output from the two committed resources, the Danskin addition (170 MW available in 2008), and the Shoshone Falls upgrade (49 MW available in 2010) are included in Idaho Power s generation forecast. Scheduled and forced outages are also incorporated in the forecast using historical data. Idaho Power used planned maintenance and traditional maintenance schedules to estimate scheduled outages. Forced outages were estimated using observed forced outage rates at the various facilities randomly assigned throughout the planning period. The hydro facility generation is directly related to the hydro forecast discussed earlier. Transmission Forecast Transmission constraints are an important factor in Idaho Power s ability to reliably serve peak- hour load conditions. Off-system spot market purchases are the last resort Idaho Power employs when its generating resources and firm purchases are inadequate to meet peak-hour load requirements. The transmission constraints on Idaho Power s system limit its ability to import off-system market purchases during certain seasons and system conditions. The transmission analysis requires hourly forecasts for the entire 20-year planning period for loads and generation levels on Idaho Power s system. The hourly transmission analysis is used to quantify the magnitude of off-system market purchases that may be required to serve the load, and determine if there will be adequate transmission capacity available to deliver the off-system purchases to the load centers. From the hourly load and generation forecasts, a determination can be made regarding the need for, and magnitude of, off-system market purchases needed to serve system load. The projected off-system market purchases are summed with all other committed transmission obligations to determine if the resulting transmission load will exceed the operational limits of Idaho Power s transmission constraints. The analysis assumes all off-system market purchases will come from the Pacific Northwest. Historically, during Idaho Power peak-hour load periods , off-system market purchases from other areas have often times proven to be unavailable or very expensive. Many of the utilities to the east and south of Idaho Power also experience a summer peak and the weather conditions that drive the summer peak are often similar across the Intermountain and Rocky Mountain West. Page 32 2006 Integrated Resource Plan Idaho Power Company 3. Planning Period Forecasts Idaho Power believes it would not be prudent to rely on imports from the Rocky Mountain region for planning purposes. Three different hydro generation/load scenarios are considered in the transmission analysis: 1. Median water / median load / 90th percentile peak-hour load 2. Seventieth percentile water and 70th percentile load / 95th percentile peak-hour load 3. Ninetieth percentile water and 70th percentile load / 95th percentile peak-hour load The results of the 90th percentile water, 70th percentile load, and 95th percentile peak-hour load case are given the most weight in the transmission adequacy analysis, since this is the most extreme of the three scenarios. One difficulty with transmission planning is while transmission resources are owned by a specific entity, they can be utilized by other parties due to the FERC' s open access requirements. Idaho Power must reserve the use of its own transmission resources under open access as well. Often, Snake River flow forecasts for the rest of the year are not known with a high degree of accuracy until Mayor June. By that time it is potentially too late to acquire firm transmission capacity for the summer months. Because of generation and transmission capacity concerns, Idaho Power believes the 95 percentile peak-hour load planning criterion is appropriate for the transmission analysis. The th percentile peak-hour load planning criterion means that there is a one-in-twenty chance Idaho Power will be required to initiate more drastic measures such as curtailing load if attempts to acquire energy and transmission access from the east and south markets are unsuccessful. The results of the transmission analysis using 90th percentile water, 70th percentile load andili 95 percentile peak-hour load scenario were used to establish a capacity target for planning purposes. The capacity target identifies the amount of internal generation, demand-side programs, or transmission resources that must be added to Idaho Power s system to avoid capacity deficits. Fuel Price Forecasts Coal Price Forecast The IRP expected coal price forecast is an average of Idaho Power s coal forecasts for its Valmy and Jim Bridger thermal plants. In addition, the IRP used a Wyoming-specific coal forecast for use in modeling prices for a resource located in Wyoming and a regional coal price forecast for a non-location specific regional coal resource. The coal price forecasts were created using current coal and rail transportation market information, private forecasts, and the Global Insight 2006 US. Power Outlook report. The resulting costs in dollars-per-MMBTU represent the delivered cost of coal, including rail costs, coal costs, and use taxes. A summary of each of the coal price forecasts can be found in Appendix D-Technical Appendix. Natural Gas Price Forecast Idaho Power does not directly forecast natural gas prices; instead it combines industry forecasts developed by outside consultants as well as forecasts from published sources. The IRP expected gas price forecast is derived from public and private source forecasts including IGI Resources, NYMEX, PIRA, EIA, NWPCC and US. Power Outlook. All source forecasts are converted to nominal dollars and then 2006 Integrated Resource Plan Page 33 3. Planning Period Forecasts Idaho Power Company converted to dollars-per-MMBTU at the Sumas trading hub. Each source forecast is given a weight and included in a total weighted average in order to forecast Sumas dollars-per-MMBTU Transportation costs are then added to the weighted average price to develop a delivered Sumas price in dollars-per-MMBTU. The transportation costs also include Northwest Pipeline s fixed and volumetric charges as well as fuel gas. The IRP high gas price forecast was derived by trending the NYMEX and IGI Resource forecasts for the period 2006-2009. This data was then trended from 2009-2013 to achieve a $1.00/MMBTU increase over the NWPCC high case starting in 2014 and thereafter. The IRP low gas price forecast was derived using the 2004 IRP expected case gas price forecast. Fuel forecast values are included in Appendix D- Technical Appendix. Page 34 2006 Integrated Resource Plan Idaho Power Company 4. Future Requirements FUTURE REQUIREMENTS Idaho Power has an obligation to serve customer loads regardless of hydrologic conditions. In the past, when water conditions were at low levels Idaho Power relied on market purchases to serve customer loads. Historically, Idaho Power plan was to acquire or construct resources to eliminate expected energy deficiencies in every month of the forecast period whenever median or better water conditions existed, recognizing when water levels were below median, it would rely on market purchases to meet any deficits. When water levels were greater than median Idaho Power would sell the surplus power in the regional markets. In connection with the market price movements to historical highs during the energy crisis of 2000 and 2001 , Idaho Power reevaluated the planning criteria as part of preparing the 2002 IRP. The public, the IPUC, and the Idaho Legislature all suggested Idaho Power placed too great a reliance on market purchases based upon the IRP planning criteria. Greater planning reserve margins or the use of more conservative water planning criteria were suggested as methods requiring Idaho Power to acquire more firm resources and reduce reliance on market purchases during low water years. Water Planning Criteria for Resource Adequacy Beginning with the 2002 IRP, Idaho Power specified a resource adequacy standard requiring new resources be acquired at the time the resources are needed to meet forecasted energy growth, assuming a water condition at the 70th percentile for hydroelectric generation. The 70th percentile means Idaho Power plans generation based on a level of streamflow that is exceeded in seven out of ten years on average. Streamflow conditions are expected to be worse than the planning criteria in three out of ten years, or 30 percent of the time. The 2006 IRP is the third resource plan wherein Idaho Power is using the 70th percentile water and 70th percentile average load conditions for energy planning. Using the 70th percentile water planning criterion produces surpluses whenever streamflows are greater than the 70th percentile. Temporary off-system sales of surplus energy and capacity provide additional revenue and reduce the costs to Idaho Power customers. During months when Idaho Power faces an energy or capacity deficit because of low streamflow, excessive demand, or for any other reason, it plans to purchase off-system energy Highlights Idaho Power uses 70th percentile average load and 70th percentile water conditions for energy planning. For peak-hour capacity planning, Idaho Power uses 90th percentile water conditions and 95th percentile peak-hour loads. ~ Peak-hour load deficiencies are greater than 500 MW by 2011 , and approximately 800 MW by 2025. The lack of available transmission capacity limits Idaho Power s ability to import additional energy during the summertime. Idaho Power currently maintains a capacity reserve margin of approximately 11 %. 2006 Integrated Resource Plan Page 35 4. Future Requirements Idaho Power Company and capacity on a short-term basis to meet system requirements. During the summer peak periods, low water conditions are more problematic than are high load conditions. The variability around the summer peak load is considerably less than the variability associated with water conditions. For example, April-July Brownlee inflow can range from under two million acre-feet to just over 11 million acre-feet. Summer high temperatures range from 98-111 degrees, meaning hot summer temperatures are more certain than are water conditions and low water conditions are likely to be the more significant planning factor. Low water scenarios have been evaluated and included in the 2006 IRP to demonstrate the viability of Idaho Power s plan to serve average and peak loads under low water conditions. Low water conditions are defined with the 90th percentile meaning Idaho Power can expect the low water conditions to occur in one out of ten years. The evaluations also include consideration ofIdaho Power s transmission capability at times of lower streamflows. The water planning criterion used by other utilities in the Pacific Northwest varies from median or 50th percentile conditions to extreme or critical water conditions. Critical water conditions are generally defined to be the worst or nearly worst, annual water conditions ever experienced based on historical streamflow records. Idaho Power utilizes a 70th percentile water planning criterion which is more conservative that median conditions, but less conservative when compared to critical water conditions. A summary of other Pacific Northwest utility planning criteria is included in Appendix D-Technical Appendix. Transmission Adequacy Historically, Idaho Power has been able to reasonably plan for the use of short-term power purchases to meet temporary water related generation deficiencies on its own system. Short-term power purchases have been successful because Idaho Power is a summer-peaking utility while the majority of other utilities in the Pacific Northwest region experience peak loads during the winter. The transmission adequacy analysis reflects Idaho Power s contractual transmission obligations to provide wheeling service to the BP A loads in southern Idaho. The BP A loads are typically served with a combination of energy and capacity from the Pacific Northwest and several BOR projects located in southern Idaho. The contractual transmission obligations are detailed in four Network Service Agreements under the Idaho Power Open Access Transmission Tariff. Although Idaho Power has transmission interconnections to the Southwest, the Pacific Northwest market is the preferred source of purchased power. The Pacific Northwest market has a large number of participants, high transaction volume, and is very liquid. The accessible power markets south and east of Idaho Power s system tend to be smaller, less liquid, and have greater transmission distances. In addition, the markets south and east of Idaho Power s system can be very limited during summer peak conditions. Recent history has shown even when power is available from the Pacific Northwest market short-term prices can be quite high and volatile. The price risk has led to the development of the Energy Risk Management Policy discussed in Chapter 1. The Energy Risk Management Policy represents the collaboration of Idaho Power, the IPUC staff, and interested customers in Commission Case IPC-01-16. Prior to 2000, Idaho Power s IRPs often emphasized acquisition of energy rather than construction of generating resources to satisfy load obligations. Transmission limitations were not a major impediment to Idaho Power Page 36 2006 Integrated Resource Plan Idaho Power Company 4. Future Requirements purchasing power to meet its service obligations. Idaho Power recognized transmission constraints began to place limits on purchased power supply strategies starting with the 2000 IRP. To better assess power supply requirements and available transmission, the 2006 IRP contains an analysis of transmission system constraints for the 20-year planning period. (See Chapter 2) Planning Reserve Margin In the past, the Western Electricity Coordinating Council (WECC) required Idaho Power to maintain 330 MW of reserves above the forecast peak-hour load to cover the worst single planning contingency which was defined to be an unexpected loss equal to Idaho Power s share of two Jim Bridger generation units. At present the WECC has dropped the planning reserve requirements. However, the North American Electric Reliability Council has approved measures requiring the WECC to reinstate some form of planning reserve requirements. Idaho Power will continue meeting the historical WECC planning reserve requirements under any planning scenario until new planning requirements are established. Idaho Power record peak-hour load is 3 084 MW, which means the current, self-imposed reserve requirement of 330 MW is equal to a reserve margin of approximately 11 percent. The future resource requirements of Idaho Power are not based directly on the need to meet a specified reserve margin. Idaho Power long-term resource planning is instead driven by the objective to develop resources sufficient to meet higher than expected load conditions under lower than expected water conditions which effectively provides a reserve margin. As a part of preparing the 2006 IRP, Idaho Power has calculated the capacity reserve margin resulting from the resource development identified in the preferred portfolio. In this process, the total resources available to meet demand consist of those made available under the preferred portfolio plus generation from existing and committed resources assuming expected water conditions. The generation from existing resources also includes expected firm purchases contracted with surrounding regional markets. The resource total is then compared with expected peak-hour loading, with the excess resource designated as reserve margin. This provides an alternative view of the adequacy of the preferred portfolio, which was developed to meet more stringent load conditions under less favorable water conditions. Capacity reserve calculations for each year throughout the planning period are included in Appendix D- Technical Appendix. Salmon Recovery Program and Resource Adequacy The December 1994 amendments to the Northwest Power Planning Council's fish and wildlife program and the biological opinions issued under the ESA for the four lower Snake River federal hydroelectric projects call for 427 000 acre-feet of water to be acquired by the federal government from willing lessors upstream of Brownlee Reservoir. The acquired water is then to be released during the spring and summer months to assist ESA-listed juvenile salmonids (spring, summer, and fall chinook and steelhead) migrating past the four federal hydroelectric projects on the lower Snake River. In the past, water releases from Idaho Power s hydroelectric generating plants have been modified to cooperate with the federal efforts. Idaho Power also adjusts flows in the late fall of each year to assist with the spawning of fall chinook below the Hells Canyon Complex. Because of the practical, physical, and legal constraints federal interests must deal with in moving 427 000 acre-feet of water out ofIdaho in the past Idaho Power has pre-released, or shaped, a portion of the acquired water with water from Brownlee Reservoir and later refilled the reservoir with water leased under the federal program. At times, Idaho Power has also contributed water from Brownlee Reservoir to 2006 Integrated Resource Plan Page 37 4, Future Requirements Idaho Power Company assist with the federal efforts to improve salmon migration past the federal government's lower Snake River projects. Planning Scenarios The timing and necessity of future generation resources are based on a 20-year forecast of surpluses and deficiencies for monthly average load (energy) and peak-hour load. For both of these areas, one set of criteria has been chosen for planning purposes; however, additional scenarios have been analyzed to provide a comparison. Table 4-1 provides a summary of six planning scenarios analyzed for the 2006 IRP and the criteria used for planning purposes are shown in bold. Median water and median load forecast scenarios were included to enable comparison of the 2006 IRP with plans developed during the 1990s. The median forecast is no longer used for resource planning, although the median forecast is used to set retail rates and avoided-cost rates during regulatory proceedings. The planning criteria used to prepare Idaho Power s 2006 IRP is consistent with the criteria used in the 2004 Integrated Resource Plan. Table 4-1. Planning Criteria for Average Load and Peak-Hour Load Average Load/Energy (aMW) th Percentile Water, 50th Percentile Average Load th Percentile Water, 70th Percentile Average Load th Percentile Water, 70th Percentile Average Load Peak-Hour Load (MW) th Percentile Water, 90th Percentile Peak-Hour Load th Percentile Water, 95th Percentile Peak-Hour Load th Percentile Water, 95th Percentile Peak-Hour Load The planning criteria used for energy or average load are 70th percentile water and 70th percentile average load. In addition, 50th percentile water and 50th percentile average load conditions are analyzed to represent a median condition, and 90th percentile water and 70th percentile average load are analyzed to examine the effects of low water conditions. Peak-hour load planning criteria consist of 90th percentile water and 95t percentile peak-hour load conditions, coupled with Idaho Power ability to import additional energy on its transmission system. A median condition of 50th percentile water and 50th percentile peak-hour load are also analyzed, as well as 70th percentile water and 95th percentile peak-hour load. Peak-hour load planning criteria are more stringent than average load planning criteria because Idaho Power s ability to import additional energy is typically limited during peak-hour load periods. Surpluses and deficiencies for the average and peak-hour load scenarios used for planning purposes can be found in Figures 4-1 and 4- Surpluses and deficiencies for the scenarios not used for planning purposes can be found in Appendix D-Technical Appendix. Average Load (Energy) The planning criteria for determining the needth for energy resources assumes 70 percent! e water and 70th percentile average load conditions. In purely statistical terms, if the two probabilities-average load and hydrological conditions-are independent, then one of the two conditions-either poor water conditions high average load conditions-can be expected in about half of the years. Figure 4-1 indicates under 70th percentile water and 70th percentile average load conditions energy deficiencies occur in July 2006 (35 aMW) and July 2007 (88 aMW). These initial deficiencies are due to the postponement of the 170 MW natural gas-fired unit at the Danskin Project. This new unit, which was identified in the 2004 IRP and was originally scheduled to come on-line in April 2007, is now expected to be operational by April 2008. Long-term summer deficiencies begin in July 2009 at 15 aMW and are expected to grow to 859 aMW by July 2025. 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Future Requirements A wintertime deficiency of 87 aMW occurs in November 2012 due to Idaho Power cooperative effort to pass water for salmon migration. Under the assumption Idaho Power will continue to adjust flows in the Hells Canyon Complex to aid salmon migration, the deficiencies in November are expected to continue to grow throughout the planning period to 586 aMW in November 2025. Deficiencies in December, which are more indicative of wintertime customer demand, start at 7 aMW in 2014 and grow to 430 aMW in 2025. This analysis assumes Idaho Power combustion turbines are in service and available to operate up to permitted limits. Although these turbines are available to meet monthly energy deficiencies, market purchases imported via the transmission system will most likely be the preferred alternative whenever transmission import capacity from the Pacific Northwest is available. Peak-Hour Load Peak-hour load deficiencies are determined using 90th percentile water and 95th percentile peak-hour load conditions, coupled with Idaho Power s ability to import additional energy on its transmission system to reduce any deficits. In addition to these criteria, 70th percentile average load conditions are assumed, but the hydrologic peak-hour load and transmission constraint criteria are the major factors in determining the peak-hour load deficiencies. Peak-hour load planning criteria are more stringent than average load criteria because Idaho Power s ability to import additional energy is typically limited during peak-hour load periods. Figure 4-2 indicates under 90th percentile water and 95th percentile peak-hour load conditions deficiencies exist during summer months throughout the planning period. Summer deficiencies from 2006-2010 remain between 350 to 400 MW due to the addition of the natural gas unit at the Danskin Project in April 2008 and the expansion of the Shoshone Falls Project in 2010. For the remainder of the planning period, deficiencies in July increase from 450 MW to 1 800 MW in 2025. Figure 4-3 indicates the amount of the peak- hour deficit (identified in Figure 4-2) that cannot be imported from the Pacific Northwest over the existing transmission system under 90th percentile water and 95th percentile peak-hour load conditions. The remaining deficiencies shown in Figure 4-3 also account for a reserve margin of 330 MW as previously discussed. In this analysis, a deficiency exists in July 2007 due to the postponement of the 170 MW natural gas-fired unit at the Danskin Project. 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