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Home My WebLink About200509012005 IRP Appendices Vol 1.pdf Technical Advisory Committee Meeting Agendas Appendix A Appendix A1 Avista Utilities Technical Advisory Committee/External Energy Efficiency Board Meeting October 23, 2003 Thursday, October 23 Integrated Resource Plan and DSM 10:00 AM – 2:00 PM 1. DSM in the 2003 IRP • Errata filed in July • Assumptions • Results 2. Integration methodologies • Avoided cost price signal • Full integration into AURORA model • Approach used in 2003 IRP (Errata) 3. Integration specifics (2003 IRP as example) • Cost attributes • Supply curves • “Resource” bundles • Load research • Other resources o Distribution efficiencies (e.g., CVR) o Peak shaving efficiencies (e.g., voluntary curtailment, TOU) 4. Issues to consider • Quality of inputs • Usefulness of outputs o Is AURORA smarter than Jon? o Examples 5. Next steps Lunch provided 12 Noon Appendix A2 Avista Utilities 2005 Integrated Resource Plan Technical Advisory Committee Meeting No. 2 August 4, 2004 • Introductions 9:30a Kalich • Overview of Planning Process and Review of IRP Schedule 9:40a Young • TAC Participant Brainstorm on IRP Topics 10:00a Folsom • Review of October 2003 DSM Meeting 11:00a Powell • Lunch Speaker & Lunch 12:00p Anderson • Load Forecast 1:00p Barcus • Future Resource Requirements (L&R) 3:00p Fletcher • Adjourn 3:30p Appendix A3 Avista Utilities 2005 Integrated Resource Plan Technical Advisory Committee Meeting No. 3 Agenda January 25, 2005 Topic Time Staff 1. Introductions 10:00 Barcus 2. Review of 2nd TAC Meeting 10:15 Kalich 3. Overview of Natural Gas Forecast 11:00 Gall 4. Capacity Planning Overview 11:30 Kalich 5. Lunch Speaker (and lunch) 12:00 Folsom 6. Capacity Planning Overview, Cont. 12:45 Kalich 7. Load Forecast Update 1:15 Barcus 8. Loads and Resources Update 1:45 Lyons 9. Imputed Debt 2:15 Thoren 10. Overview of Feb. 17 TAC Meeting 2:45 Kalich 11. Adjourn 3:00 Appendix A4 Avista Utilities 2005 Integrated Resource Plan Technical Advisory Committee Meeting No. 4 Agenda 4th Floor Technology Room—Avista Headquarters, Spokane February 17, 2005 Topic Time Staff 1. Introductions 10:00 Kalich 2. Review of 3rd TAC Meeting 10:15 Kalich 3. IRP Modeling Overview 10:30 Gall 4. Modeling Futures and Scenarios 11:00 Kalich 5. More on Modeling Assumptions 11:45 Gall 6. Lunch and AURORAXMP Demo 12:15 Gall 7. Modeling Emissions in IRP 1:15 Lyons 8. Supply-Side Resource Alternatives 2:45 Gall/Lyons 9. Selection of Future TAC Dates 3:30 Kalich 10. Adjourn 4:00 Appendix A5 Avista Utilities 2005 Integrated Resource Plan Technical Advisory Committee Meeting No. 5 Agenda 4th Floor Technology Room—Avista Headquarters, Spokane March 23, 2005 Topic Time Staff 1. Introductions 10:00 Barcus 2. Review of 4th TAC Meeting 10:15 Lyons 3. DSM Integration Into IRP 10:30 Powell 4. Stochastic (Risk) Modeling Part 1 11:30 Kalich 5. Lunch and Transmission Planning Discussion 12:00 Cloward 6. Stochastic (Risk) Modeling Part 2 1:00 Kalich 7. Preliminary Capacity Expansion Results 1:30 Gall 8. Update on Scenarios & Futures 2:15 Lyons 9. 2005 Draft IRP Outline 2:45 Lyons 10. Adjourn 3:00 Appendix A6 Avista Utilities 2005 Integrated Resource Plan Technical Advisory Committee Meeting No. 6 Agenda May 18, 2005 Topic Time Staff 1. Introductions 10:00 Barcus 2. Review of 5th TAC Meeting 10:15 Lyons 3. Natural Gas Price Forecast Update 10:30 Gall 4. Base Case Results 10:45 Gall 5. LP Module/Selection Criteria 11:45 Kalich 6. Lunch 12:30 7. Transmission Planning 1:00 Waples 8. Scenario Results 2:00 Lyons 9. Avoided Costs 2:45 Kalich 10. Action Item for 2005 IRP 3:15 Kalich 11. Housekeeping Items 3:45 Lyons 12. Adjourn 4:00 Appendix A7 Avista Utilities 2005 Integrated Resource Plan Technical Advisory Committee Meeting No. 7 Agenda June 23, 2005 Topic Time Staff 1. Introductions 10:00 Barcus 2. Review of 6th TAC Meeting 10:15 Lyons 3. Hydro Upgrades 10:30 Kalich 4. Emissions 11:00 Lyons 5. Lunch 12:00 6. DSM 1:00 Powell 7. Preferred Resource Strategy 3:00 Kalich 8. Adjourn 4:00 Appendix A8 Technical Advisory Committee Members Appendix B Appendix B1 2005 IRP TAC Member List Name Organization Phone Number E-Mail TAC1 TAC2 TAC3 TAC4 TAC5 TAC6 TAC7 Aliza Seelig Puget Sound Energy 425.462.3122 aliza.seelig@pse.com X Andy Ford WSU FordA@mail.wsu.edu X X X Bruce Folsom Avista Utilities 509.495.8706 bruce.folsom@avistacorp.com X X X X Charlie Grist NPCC 503.222.5161 cgrist@nwcouncil.ort X Chris Bevil Puget Sound Energy 425.456.2757 chris.bevil@pse.com X Chris Turner PacifiCorp 503.813.6114 chris.turner2@pacificorp.com X Clint Kalich Avista Utilities 509.495.4532 clint.kalich@avistacorp.com X X X X X X Danielle Dixon NW Energy Coalition 206.621.0094 danielle@nwenergy.org X Dave Van Hersett NW Energy Services 509.838.9190 davev@nwenergy.com X X X X X Diane Thoren Avista Utilities 509.495.4331 X Doug Loreen Puget Sound Energy 425.454.2988 doug.loreen@pse.com Doug Young Avista Utilities X X Hank McIntosh WUTC 360.664.1309 hmcintos@wutc.wa.gov X X X X X X Harry McLean City of Spokane 509.625.7804 hmclean@spokanecity.org X Heidi Heath Avista Utilities 509.495.4129 heidi.heath@avistacorp.com X Howard Ray Potlatch 208.799.1030 Howard.Ray@potlatchcorp.com X X X James Gall Avista Utilities 509.495.2189 james.gall@avistacorp.com X X X X X Jamie Stark Idaho Power 208.388.5648 X Jason Fletcher Avista Utilities X X Joe Brabeck Avista Utilities 509.495.4108 joe.brabeck@avistacorp.com X X Joelle Steward WUTC 360.664.1308 jsteward@wutc.wa.gov X X X John Lyons Avista Utilities 509.495.8515 john.lyons@avistacorp.com X X X X X John Seymour FPL Energy 561.691.7138 john_seymour@fpl.com X Jon Powell Avista Utilities 509.495.4047 jon.powell@avistacorp.com X X X X Ken Canon ICNU 503.239.9169 kcanon@icnu.org X Leonard Coldiron Potlatch 208.799.7483 Leonard.coldiron@potlatchcorp.com X Liz Klumpp WCTED 360.956.2071 ElizabethK@ep.cted.wa.gov X X X X X Lynn Anderson IPUC 208.334.0350 landers@puc.state.id.us X Mallur Nandagopal City of Spokane 509.625.7811 MNandagopal@SpokaneCity.org X Patrick Saad Dana-Saad Co. 509.924.6711 patsaad@qwest.net X X Randy Barcus Avista Utilities 509.495.4160 randy.barcus@avistacorp.com X X X X X X Renee Coelho Avista Utilities 509.495.8607 renee.coelho@avistacorp.com X X Richard Nagy Univ. of Idaho 208.885.7350 richardn@uidaho.edu X X Rick Sterling IPUC 208.334.0351 rsterli@puc.state.id.us X X X X X X Steve Silkworth Avista Utilities 509.495.8093 steve.silkworth@avistacorp.com X Terry Morlan NPCC 503.222.5161 tmorlan@nwcouncil.org X Tom Dempsey Avista Utilities 509.495.4960 tom.dempsey@avistacorp.com X X Tom Eckman NPCC 503.222.5161 teckman@nwcouncil.org X X Tom McLaughlin Potlatch 208.799.1935 Tom.McLaughlin@potlatchcorp.com X X Yohannes Mariam WUTC 360.664.1316 ymariam@wutc.wa.gov X X X Appendix B2 Technical Advisory Committee Meeting Presentation Slides Appendix C Appendix C1 TAC Presentation Table of Contents TAC 1 October 23, 2003 Integration of DSM into the IRP TAC 2 August 4, 2004 Overview of Planning Process TAC Brainstorming Review Summary Avista Electric Demand Side Management- Update and Proposed Integration Clark Fork River Projects Update Spokane River Relicensing Update 2005 Load Forecast Future Resource Requirements TAC 3 January 25, 2005 Overview of Natural Gas Forecast Sustained Capacity and Planning Margin Concepts 2005 Load Forecast Update and Scenarios Future Resource Requirement Update Imputed Debt Discussion TAC 4 February 17, 2005 Modeling Overview and Process Modeling Futures and Scenarios Modeling Assumptions Treatment of Emissions Supply Side Options TAC 5 March 23, 2005 DSM Integration Brief Stochastic Modeling Avista’s 230kV Upgrade Projects Preliminary Long-term Electric Forecast and Capacity Expansion Results Modeling Futures and Scenarios 2005 Draft IRP Outline TAC 6 May 18, 2005 Gas & Inflation Forecast Update Base Case Results- Electric Price Forecast LP Module, The Selection Criteria & Efficient Frontier Estimated Resource Integration Costs for the 2005 IRP Scenario Results Avoided Costs TAC 7 June 23, 2005 Hydro Upgrades Emissions Demand Side Management Preferred Resource Strategy Appendix C2 Integration of DSM into the IRP Integration of DSM into the IRP Technical Advisory Committee Triple-E Board Meeting October 23, 2003 Jack Stewart Training Center DSM in the 2003 IRPDSM in the 2003 IRP • Errata filed in July – New DSM run – third time’s a charm! • Assumptions • Results DSM in the IRP Appendix C3 2003 IRP Assumptions2003 IRP Assumptions • DSM bundles – Based on actual conservation activities – Six components account for vast majority of historic energy savings: • Commercial DHW, HVAC, and lighting • Residential DHW, HVAC, and lighting DSM in the IRP > 2003 IRP 2003 IRP Assumptions2003 IRP Assumptions • DSM supply curves – For each component, curves were based on actual and three incremental points – Incremental points – 25% increase in funding results in 10% increase in savings DSM in the IRP > 2003 IRP Appendix C4 2003 IRP Assumptions2003 IRP Assumptions • DSM load shapes – Hourly shapes estimated for typical week for each of twelve months – Based on internal M&E and BPA End Use Load and Consumer Assessment Program (ELCAP) – Modified to include engineering estimates of new technologies DSM in the IRP > 2003 IRP 2003 IRP Assumptions2003 IRP Assumptions DSM in the IRP > 2003 IRP 0% 20% 40% 60% 80% 100% 120% Sunday Monday Tuesday Wednesday Thursday Friday Saturday Typical Week Pe r c e n t o f C a p a c i t y Com HVAC Com Ltg Com DHW Res HVAC Res Ltg Res DHW Illustration – August Load Shapes Appendix C5 2003 IRP Results2003 IRP Results DSM in the IRP > 2003 IRP Measure NPV Status Com HVAC 1 861.8 pass Com HVAC 2 1.2 pass Com HVAC 3 -10.5 fail Com HVAC 4 -2.4 fail 8,480 MWh passed Res HVAC 1 238.2 pass Res HVAC 2 16.5 pass Res HVAC 3 0.7 pass Res HVAC 4 0.0 fail 1,563 MWh passed Measure NPV Status Com Light 1 3,159.3 pass Com Light 2 268.8 pass Com Light 3 21.0 pass Com Light 4 1.4 pass 12,931 MWh passed Res Light 1 2,664.5 pass Res Light 2 218.4 pass Res Light 3 15.8 pass Res Light 4 0.8 pass 9,007 MWh passed 32,302 selected by AURORA 3,142 “odd-ball” 2,365 limited income 37,810 total MWh (or 4.32 aMW) Measure NPV Status Com DHW 1 64.0 pass Com DHW 2 5.5 pass Com DHW 3 0.4 pass Com DHW 4 0.0 pass 255 MWh passed Res DHW 1 3.3 pass Res DHW 2 -0.3 fail Res DHW 3 -0.1 fail Res DHW 4 -0.0 fail 69 MWh passed 2003 IRP Results2003 IRP Results DSM in the IRP > 2003 IRP $0 $10 $20 $30 $40 $50 $60 Q1 Q2 Q3 Q4 Co s t ( $ / M W h ) Price Res HVAC 1 Res HVAC 2 Res HVAC 3 Res HVAC 4 Illustration – Residential HVAC vs. 2004 Prices Appendix C6 Integration MethodologiesIntegration Methodologies • Avoided cost price signal • Full integration into AURORA model • Approach used in 2003 IRP DSM in the IRP Avoided Cost Price SignalAvoided Cost Price Signal DSM in the IRP > Integration Methods AURORA Resource Stacks WECC Supply-Side Resources Deferrable Resource Avoided Cost DSM Department “Goes & Gets” Decrement Deferrable Resource by Amount of DSM Appendix C7 Full Integration Into AURORAFull Integration Into AURORA DSM in the IRP > Integration Methods AURORA Resource StacksWECC Supply-Side Resources AURORA Selection of Demand-Side Resources ?Load Shapes DSM Bundles Supply Curves Cost Attributes Avista Demand-Side Resources Approach Used In 2003 IRPApproach Used In 2003 IRP DSM in the IRP > Integration Methods AURORA Resource Stacks WECC Supply-Side Resources Pass/Fail DSM Resource Bundles ?Load Shapes DSM Bundles Supply Curves Cost Attributes Avista Demand-Side Resources Appendix C8 Integration SpecificsIntegration Specifics • Cost attributes • Supply curves • DSM bundles • Load shapes DSM in the IRP • Other resources – Distribution efficiencies (CVR) – Peak shaving (voluntary curtailment) – Load shifting (TOU) Issues to ConsiderIssues to Consider • Quality of inputs – Supply curves, bundles, and load shapes • Usefulness of outputs – Is AURORA smarter than Jon? – Examples DSM in the IRP Appendix C9 Next Steps?Next Steps? DSM in the IRP Appendix C10 Overview ofOverview of Planning ProcessPlanning Process 2005 Integrated Resource Plan Second Technical Advisory Committee Meeting August 4, 2004 Doug Young Overview of Planning ProcessOverview of Planning Process • Avista is continuously evaluating the balance between requirements and resources. • Avista does an update each year when the new load forecast is completed. • Avista strives to reach balanced business decisions. Appendix C11 Overview of Planning ProcessOverview of Planning Process • The Company expects public participation will continue to play an important role in resource planning. • This is the eighth IRP that will be submitted since 1989. • The plan’s goal is to describe the mix of generating resources and improvements in efficiency that is expected to meet future needs at the lowest cost to the Company and its customers. • The 2003 IRP focused on developing a set of tools and methods within which potential resource decisions could be evaluated. Overview of Planning ProcessOverview of Planning Process • The Company’s near-term action plan outlined activities that supported the Preferred Resource Strategy (PRS) and improved the planning process. During the first ten years the PRS includes: - 149 aMW of CCCT - 25 aMW of wind - 197 aMW of coal - 40 aMW of SCCT Appendix C12 Overview of Planning ProcessOverview of Planning Process • Work is proceeding on some of the action items, such as: - Spokane River relicensing effort, - Integrating wind generation into Avista’s system, - Adding coal facilities to the resource mix, - Determining the optimum reserve margin, and - Assessing the cost-effectiveness of new resource additions Review of 2005 IRP ScheduleReview of 2005 IRP Schedule • Avista had four TAC meetings during the last IRP planning cycle. • In October 2003 Avista held its first TAC meeting for the 2005 IRP planning cycle to discuss the various alternatives for integrating DSM into the IRP process. • The Company will hold TAC meetings in October and December of this year. Another TAC meeting will be held in February 2005, and the draft IRP will be released in March. A final TAC meeting to review the draft report will be held the first of April. The final IRP report will be released at the end of April. Appendix C13 Review of 2005 IRP ScheduleReview of 2005 IRP Schedule • This will be Doug’s last IRP. Doug is retiring at the end of 2004! Appendix C14 August 4, 2004 IRP TAC Brainstorming Summary Issue Area Index Details of Issue Utility Response 1 Risk Analysis consider fuel supply and price risk, as well as value of resource diversity will be evaluated 2 DSM Buybacks Council is focusing on buy-backs and would like utility to consider it in 2005 IRP will include in plan 3 L&R Capacity discuss what planning capacity is (single- versus multi-hour peak) include in plan 4 L&R Capacity discuss if adjusting hydro maintenance/upgrades would eliminate need for additional peaking plants include in plan 5 L&R Capacity Look to hydro for new capacity include in plan 6 DSM Codes Model future code revisions and quantify their impact on load forecast The econometric forecast methodology captures improved energy codes. Improvements over and above the code are quantified within the DSM resource acquisition. 7 Resources Cogen Keep Cogen discussion in '05 IRP will include in IRP 8 Resources Cogen Include discussion on what makes a good cogen project (maybe to appendix?) look to power council, AVA research 9 Resources Cogen emphasize importance of flexibility, dispatchability, as historical projects haven't been perfect fits include in discussion above 10 Resources Cogen Do we have estimate of cogen potential? Consider strength of cogen facility (i.e., how long will it be around) in matrix include discussion of potential 11 Resources Cogen Rate structure makes cogen hard. Consider demand charges with ratchets, seasonal rates, TOU, etc. include in discussion, recognizing this as rate issue 12 Resources Cogen Cogen makes more sense in a transmission constrained region than any other form of generation because it will occur at a load center and it provides twice the usage of some portion of the natural gas include in discussion 13 Risk Contingency Planning Develop plan for the shelf to use in event of 00-01 happening again (ST solution for ST problems) Evaluate the development of DSM-funded contingency plans to include customer buyback and various emergency DSM options 14 Credit Credit Discuss pros and cons of PPA versus ownership of resources include in discussion 15 Resources DG discuss DG and its impact on transmission/distribution systems include in discusion 16 DSM DSM Be aggressive on DSM, AVA should consider higher incentives literature search & consider controlled experiment on higher incentives Appendix C15 August 4, 2004 IRP TAC Brainstorming Summary Issue Area Index Details of Issue Utility Response 17 DSM DSM Evaluate accelerating the DSM acquisition schedule We will review the assumptions and methodology behind the slight front-loading of the draft 20-year regional supply curve. Avista is currently engaging in a significant expansion of DSM resource acquisition. 18 Resources Emissions consider risk of future emission (CO2 and Mercury) will be evaluated as scenarios, consider including in stochastic runs 19 Risk Emissions look at a couple levels of mitigation costs when evaluating impact on resource decisions will evaluate as scenarios 20 Risk Gas consider buying gas model or a consultant forecast Company purchases Global Insights forecast 21 Resources IPP Consider IPP plants in plan include in plan 22 L&R L&R include monthly L&R tables in IRP will include in tech. Appendix 23 L&R L&R Include 24-hour seasonal load shapes for utility, by customer class where available will include system hourly loads by season, as class-level data is not available 24 L&R L&R Evaluate forecasts besides base case, what happens if Fairchild Airforce Base closes, expands will include hi/lo forecasts & scenarios, including discussion of FAB changes 25 L&R L&R look at plans to address supply/demand shocks (FAB closure, Noxon failure, etc.)include in plan 26 DSM Load Control If IRP finds it a good idea, recognize need to go in for rate schedule changes to address cost shifts include in discussion 27 Risk Loads Plan of how utility will address changing conditions (e.g., new load or load loss). How would a LT commitment to a coal plant be addressed if after the decision load fell include in IRP discussion/scenarios 28 Resources Nuclear Consider this resource to address emissions and availability of fossil fuels add as resource alternative to IRP 29 Risk Risk Address how long-term risk planning transitions to short-term risk management procedures include in discussion 30 Risk Risk Evaluate the hedge value of efficiency and renewables will be included in analysis/discussion 31 DSM Supply Curves develop supply curves for IRP, possibly starting with NPCC curves Review regional DSM supply curves to determine if they can be extrapolated to Avista’s DSM portfolio 32 Trans. Trans. Discuss transmission in plan include in plan 33 Resources Wind Look at studies out there on wind integration to see what the latest information is will include extensive eval. of wind in IRP Appendix C16 Avista Electric Demand-Side Management Avista Electric Demand-Side Management Operational Update and Proposed IRP Integration August 4, 2004 Avista Electric DSMAvista Electric DSM • Operational update – Where we are • Proposed methodology for assessing Avista DSM potential in the IRP – Where we’re going Appendix C17 DSM FundingDSM Funding • Washington – $/kWh tariff rider – An amount equal to 1.48% of retail rates • Idaho – Tariff rider established at 1.95% of retail rates • These amounts do not include non-efficiency funding received through the same tariff rider Proposed Revisions to the Idaho Tariff Rider Mechanism Proposed Revisions to the Idaho Tariff Rider Mechanism • Revise tariff rider mechanism to break the % tie to retail rates • Institute a “PGA-style” procedure that annually establishes a tariff rider level based upon – Estimated budget necessary to acquire all cost-effective kWhs – Carryover balance (positive or negative) Appendix C18 Proposed Revisions to the Idaho Electric Tariff Rider Level Proposed Revisions to the Idaho Electric Tariff Rider Level • Reduce tariff rider to an amount equal to 1.25% of current retail rates • Funding sufficient to support a three-fold increase in expenditures Current and Proposed Funds Available for DSM $- $500,000 $1,000,000 $1,500,000 $2,000,000 $2,500,000 $3,000,000 Current Proposed Balance carryover Revenue @ 1.25% of current rate Prior years unexpended funds Prior years expended funds Effect of these RevisionsEffect of these Revisions • Increased responsiveness – Financial resources will be available when needed to acquire additional DSM resources • Avista will fund cost-effective kWh acquisition at the expense of establishing a negative intra-year tariff rider balance – There will be a timely reduction in the tariff rider when necessary to eliminate positive balances Appendix C19 Tariff Rider Balance Projections (in the absence of ramp-up programs) Actual and Projected Rider Balances $(10,000,000) $(8,000,000) $(6,000,000) $(4,000,000) $(2,000,000) $- $2,000,000 $4,000,000 $6,000,000 January March May July September November January March May July September November January March May July September November January March May July September November January (BOM) WA Electric WA E pro jected ID Electric ID E pro jected DSM Target Markets and Focus • Washington Electric – Lost opportunities • Leave no lost opportunity behind – Low-Cost / No-Cost measures • Target measures that have the maximum immediate benefit to the customer – Preparing for early 2005 ramp-up • Idaho Electric – Any kWh that can be cost-effectively acquired through utility programs Appendix C20 Ramp-up Programs and Targets • Idaho – Any cost-effective kWh • Without regard to system coincidence – Implementing a series of “ramp-up” programs • 65 concepts developed • 25 concepts short-listed • 8 programs fielded • 9 programs nearing implementation • Generating concepts for next wave of programs Launched & Developing Ramp-up programs New Programs and Efforts • Educational PSA’s • Indirect Evaporative Cooling • Participate in regional leveraging opportunities – E.g. “Double Your Saving” Programs in Development • Residential Controls Program • Residential Lighting Program – Torchieres – New generation CFL’s – Hardwired exterior Energy Star Lights • Energy Star Home Products • Next Generation Outdoor Lighting Control Products Launched Enhancements to Current Portfolio • Prescriptive Motor program • Enhanced marketing of Prescriptive Lighting program • Intensified follow-up on previously identified opportunities • Rooftop HVAC Maintenance program • Prescriptive High Bay Lighting program Enhancement Programs in Development • Idaho residential program bill stuffers • Prescriptive Compressed Air Program • Efficiency “kit” for specified building types • Industry Resource Management Support Group Appendix C21 Electric Savings Commitments • Committed to delivering energy savings that were at least proportionate to expenditures – Analysis of Business Plan activity 1-1-02 to 10-31-03 • Expended $6.8 million of $14.3 million tariff rider revenues (48%) • Achieved 87% of tariffed energy savings goal • Proportionality 181% Electric DSM Acquisition 0.00 5.00 10.00 15.00 20.00 25.00 0 10 20 30 40 50 60 Months aM W Actual aMW aMW goal Avista’s Current Electric DSM Programs • Commercial/Industrial qualifying measures – Any electric efficiency measure – Any electric to natural gas conversion measure exceeding the electric efficiency of deferrable natural gas-powered electrical generation • Limited Income qualifying measures – Any electric efficiency measure – Any electric to natural gas conversion measure exceeding the electric efficiency of deferrable natural gas-powered electrical generation • Residential qualifying measures – Heat pumps – High-Efficiency Water Heaters – Weatherization – Electric to Natural Gas Conversion • Solar, wind or geothermal distributed generation – Customer owned, under 25 kW and not exceeding 50% of total customer load Appendix C22 Implementation • Based upon a tiered incentive structure – “Standard” electric efficiency • 18 to 48 month customer simple payback Æ 4 cents per 1st year kWh • 48 to 72 month customer simple payback Æ 6 cents per 1st year kWh • Over 72 month customer simple payback Æ 8 cents per 1styear kWh • Subject to 50% of incremental measure cost ceiling – “New Technology” electric efficiency • Under 48 month customer simple payback Æ 10 cents per 1st year kWh • 48 to 72 month customer simple payback Æ 12 cents per 1st year kWh • Over 72 month customer simple payback Æ 14 cents per 1st year kWh • Subject to 75% of incremental measure cost ceiling – Fuel-Conversion • 24 to 48 month customer simple payback Æ 1 cent per 1st year kWh • 48 to 72 month customer simple payback Æ 2 cents per 1st year kWh • Over 72 month customer simple payback Æ 3 cents per 1styear kWh • Subject to 50% of incremental measure cost ceiling • Incentives for prescriptive programs and all residential programs are defined based upon typical installations • Tiered incentive structure does not apply to limited income programs Planning for the Future • Use the IRP planning process as a meaningful exercise – Seeking actionable management actions • Target market focus • Long-range infrastructure planning • Revisions in valuation of DSM • Review of incentive levels – Unnecessary to incorporate into IRP • Budgeting • Tariff rider requirements forecasting • Long-range objective … – Any kWh that can be cost-effectively acquired through utility programs Appendix C23 Past Integrations of DSM into the IRP • Integration by price signal – DSM acquires all achievable kWh’s at or below the IRP-calculated avoided cost • Results in appropriate acquisition level as long as DSM is sufficiently small to be a price taker • Leads DSM to target the appropriate resources Avoided Cost Price SignalAvoided Cost Price Signal DSM in the IRP > Integration Methods AURORA Resource Stacks WECC Supply-Side Resources Deferrable Resource Avoided Cost DSM Department “Goes & Gets” Decrement Deferrable Resource by Amount of DSM Appendix C24 Explicitly Model DSM as a Resource • Define DSM “bundles” that can be characterized within Aurora – Modeling issues • Defining DSM bundles to mimic supply-side resources – Sensitive to load research quality and applicability – Difficulty in establishing incremental / decremental resources available • Estimates must be specific to Avista service territory • Estimates are specific to an assumed time horizon • Distinctions between movements in a supply curve vs. movements along a supply curve Approach Used In 2003 IRPApproach Used In 2003 IRP DSM in the IRP > Integration Methods AURORA Resource Stacks WECC Supply-Side Resources Pass/Fail DSM Resource Bundles ?Load Shapes DSM Bundles Supply Curves Cost Attributes Avista Demand-Side Resources Appendix C25 Proposed Methodology Attributes • Adaptation of both the price signal and full integration approach • Specific to the mid- and long-term management decisions regarding DSM operations and infrastructure development. – Should we target system-coincident and/or disproportionately on-peak end-uses? – Is our current incentive structure in need of revision? • Increase or decrease incentive levels? • Incorporate a preference for measures based upon load shape? Methodology • Disaggregate promising DSM measures into meaningful bundles – Including measures not currently significantly represented in our portfolio • Estimate load shapes specific to that bundle and the most likely efficiency measures • Apply measure / bundle specific load shapes against an 8760-hour avoided cost matrix to determine measure viability • Actionable items – Target appropriate measures – Determine the value of targeting system coincident or on-peak measures – Evaluate revisions in tiered incentive structure based upon the differential per kWh value of energy savings of various measures / bundles / load shapes Appendix C26 Proposed Methodology FlowProposed Methodology Flow DSM in the IRP > Integration Methods AURORA Resource StacksWECC Supply-Side Resources AURORA Identifies 8760 Hour AC Determination of value of DSM bundle Load Shapes DSM bundles Cost Attributes Avista Demand-Side Resources Targeting of measure(s) Review of incentive format & level Establish appropriate infrastructure for operation Other Related Issues • Conservation Voltage Regulation (2003 IRP action item) – Unlikely to have sufficient results from Avista’s pilot to support testing in this IRP – Will not have sufficient data for testing all alternative CVR technologies and their application to Avista’s distribution system Appendix C27 Total Dissolved Gas (TDG) Supersaturation Clark Fork Project: Cabinet Gorge and Noxon Rapids Hydroelectric Developments Noxon Rapids HED Appendix C28 Cabinet Gorge HED Issue Identification • State and Federal standards limit TDG levels to 110% • TDG issue was identified during relicensing • TDG issues at Noxon Rapids were easily resolved • Resolution process at Cabinet Gorge incorporated into Clark Fork Settlement Agreement Appendix C29 FERC License Requirements • Monitor TDG levels in the Clark Fork-Lake Pend Oreille system • Develop interim TDG abatement alternatives • Conduct biological studies • Conduct “engineering study” to determine “default strategy” • Develop Gas Supersaturation Control Program (GSCP) in 2002 Avista’s Strategy 1. Propose mitigation in lieu of structural modification 2. Propose single or phased bypass tunnels with mitigation 3. Propose concurrent construction of two bypass tunnels (estimated cost=$55 million, including AFUDC) *Neither default strategy or alternatives meet state/federal standards Appendix C30 Plan • Engineering/Geotech (2004-07) • Construct 1st Tunnel (2008-09) • Evaluate (0-10 years) • Decision on 2nd Tunnel Financial • One Tunnel ($ 38 Million) • Annual Mitigation ($ 0.5 Million) Appendix C31 UtilitiesWe are Avista…We improve life’s quality…With energy Spokane River Relicensing Long Lake Powerhouse - 1999 TECHNICAL ADVISORY COMMITTEE MEETING AUGUST 4, 2004 Spokane River FERC Project Appendix C32 August 4, 2004 3 UtilitiesWe are Avista…We improve life’s quality…With energy Post Falls Facility One of five in FERC License 2545 August 4, 2004 4 UtilitiesWe are Avista…We improve life’s quality…With energy Post Falls Facility Data Located about 9 miles downstream from Coeur d’Alene Lake Initial operation in 1907 Generation - 9.5 average megawatts, 5400 cfs flow Powerhouse Capacity - 15 MW Powerhouse Capacity - 5400 cubic feet per second (cfs) Project Capacity - 42,000 cfs Minimum flow - 300 cfs Appendix C33 August 4, 2004 5 UtilitiesWe are Avista…We improve life’s quality…With energy ♦Construction completed and first operation 1922 ♦“Run of river” facility with no operating storage ♦Generating Capacity - 10 MW ♦Average annual flow - 6,570 cfs ♦Powerhouse capacity - 2,500 cfs Upper Falls Facility August 4, 2004 6 UtilitiesWe are Avista…We improve life’s quality…With energy ♦Construction completed and first operation in 1890 ♦“Run of river” facility with no operating storage ♦Minimum flow over dam - 200 cfs during viewing hours ♦Generating Capacity - 15 MW ♦Average annual flow - 6,570 cfs ♦Powerhouse capacity - 2,850 cfs Monroe Street Facility Appendix C34 August 4, 2004 7 UtilitiesWe are Avista…We improve life’s quality…With energy Nine Mile Facility ♦Construction completed and first operation in 1908 ♦Total usable storage - 3,130 acre feet ♦Average annual inflow - 7,100 cfs ♦Full pool forebay elevation - 1606.6 with 10’ flashboards ♦Powerhouse turbine capacity (4 units) - 6,400 cfs ♦Generating Capacity - 26 MW ♦Limited Storage Capacity Facility August 4, 2004 8 UtilitiesWe are Avista…We improve life’s quality…With energy Long Lake Facility Appendix C35 August 4, 2004 9 UtilitiesWe are Avista…We improve life’s quality…With energy Long Lake Facility Data ♦Construction completed and first operation in 1915 ♦Full pool surface elevation - 1,536 ft ♦Reservoir storage in top 14’ - 65,270 acre feet ♦Generating Capacity - 72 MW ♦Spillway capacity - 115,000 cfs at 1535 ft ♦Average annual inflow - 7,650 cfs ♦Powerhouse turbine capacity (four units) - 7,000 cfs How the Spokane River Plants Help Keep the Lights On -- Spokane River Generation Compared to Customer Load Requirements 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Hours Me g a w a t t L o a d Customer Load 3/23/01 Spokane River Generation Spokane River Plant Generation on March 23, 2001 Avista Customer Load Requirement on March 23, 2001 Average Load = 895 MW Average Spokane River Plant Generation = 125 MW Appendix C36 August 4, 2004 11 UtilitiesWe are Avista…We improve life’s quality…With energy Operational Flexibility ♦Turbines sized at about average river flow or less ♦100 MW Energy -- 138 MW Capacity ♦Only Long Lake has peaking capability ♦Turbines sized at about twice the average river flow ♦328 MW Energy -- 780 MW Capacity ♦40 - 780 MW Peaking/Load following capability ♦Daily to weekly storage Spokane River Clark Fork River August 4, 2004 12 UtilitiesWe are Avista…We improve life’s quality…With energy FERC Licenses ♦Describe the facilities and operations ♦Contain protection, mitigation and enhancement measures (PM&E) for project associated resources Spokane River Project FERC No. 2545 LICENSE Issued 1972 Amended 1981 Expires 2007 Appendix C37 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 Spokane River Relicensing Regulatory Time-Line Regulatory "Have To's" File Notice of Intent between 1/02 and 7/02 File Application 7/05 License Expires 7/07 August 4, 2004 14 UtilitiesWe are Avista…We improve life’s quality…With energy Alternative Licensing Process Features ♦Collaborative Group designs the pre-application process - communications protocol, scoping, studies & study reports, procedures & deadlines ♦Applicant files a preliminary draft NEPA document with application Appendix C38 August 4, 2004 15 UtilitiesWe are Avista…We improve life’s quality…With energy Summary ♦96 stakeholder groups involved in 5 work groups and several sub groups and the plenary ♦137 meetings held since May 2002 ♦Interests identified, studies underway/completed and 17 PM&Es in draft ♦Challenges include diversity of interests, number of participants, information needs, limited financial resources, and number of mandatory conditioning authorities Appendix C39 1 2005 Load Forecast Presented by Randy Barcus, Avista Corp. Chief Economist August 4, 2004 2 Forecast Discussion Points • Economic Forecast – Employment – Population – Scenario Options • Degree Days – Heating – Cooling • Prices – Electric--Retail – Natural Gas—Retail and Wholesale • Electric Base Case Results Appendix C40 3 Economic Forecast • Global Insight, Inc. Contract – National Outlook – Spokane County, Washington – Kootenai County, Idaho • Adjustments – Fairchild Air Force Base Assessment – Economic Development Initiatives • Allocation Scenario 4 National Outlook Appendix C41 5 National Outlook 6 National Outlook Appendix C42 7 National Outlook 8 National Outlook Appendix C43 9 Regional Economy • Service Area Population 900,000 • Principal Counties—Growth Proxy – Spokane, Washington 440,000 – Kootenai, Idaho 125,000 • Largest Employers – Fairchild Air Force Base – School Districts – Hospitals 10 Regional Economy • Risks to Growth – Military Base Realignment and Closure Process during 2005 – Continued Meltdown in Manufacturing • Opportunities for Growth – Base expands with new missions – University District, Airport Freight Hub, Technology Parks – Convention Center Construction Underway Appendix C44 11 Regional Outlook--Jobs (4) (2) 0 2 4 6 8 10 12 90 t o 9 1 91 t o 9 2 92 t o 9 3 93 t o 9 4 94 t o 9 5 95 t o 9 6 96 t o 9 7 97 t o 9 8 98 t o 9 9 99 t o 0 0 00 t o 0 1 01 t o 0 2 02 t o 0 3 03 t o 0 4 04 t o 0 5 05 t o 0 6 06 t o 0 7 07 t o 0 8 08 t o 0 9 09 t o 1 0 10 t o 1 1 11 t o 1 2 12 t o 1 3 13 t o 1 4 14 t o 1 5 15 t o 1 6 16 t o 1 7 17 t o 1 8 18 t o 1 9 19 t o 2 0 20 t o 2 1 21 t o 2 2 22 t o 2 3 23 t o 2 4 24 t o 2 5 Ne t J o b C h a n g e Y e a r t o Y e a r 1990-2000growth 62,000 12 Regional Outlook--Jobs (4) (2) 0 2 4 6 8 10 12 90 t o 9 1 91 t o 9 2 92 t o 9 3 93 t o 9 4 94 t o 9 5 95 t o 9 6 96 t o 9 7 97 t o 9 8 98 t o 9 9 99 t o 0 0 00 t o 0 1 01 t o 0 2 02 t o 0 3 03 t o 0 4 04 t o 0 5 05 t o 0 6 06 t o 0 7 07 t o 0 8 08 t o 0 9 09 t o 1 0 10 t o 1 1 11 t o 1 2 12 t o 1 3 13 t o 1 4 14 t o 1 5 15 t o 1 6 16 t o 1 7 17 t o 1 8 18 t o 1 9 19 t o 2 0 20 t o 2 1 21 t o 2 2 22 t o 2 3 23 t o 2 4 24 t o 2 5 Ne t J o b C h a n g e Y e a r t o Y e a r 2005-2015No Action +41,000FAFB + ED +29,000Total +70% faster1990-2000growth 62,000 Appendix C45 13 Regional Outlook--Persons 0 2 4 6 8 10 12 14 16 90 t o 9 1 91 t o 9 2 92 t o 9 3 93 t o 9 4 94 t o 9 5 95 t o 9 6 96 t o 9 7 97 t o 9 8 98 t o 9 9 99 t o 0 0 00 t o 0 1 01 t o 0 2 02 t o 0 3 03 t o 0 4 04 t o 0 5 05 t o 0 6 06 t o 0 7 07 t o 0 8 08 t o 0 9 09 t o 1 0 10 t o 1 1 11 t o 1 2 12 t o 1 3 13 t o 1 4 14 t o 1 5 15 t o 1 6 16 t o 1 7 17 t o 1 8 18 t o 1 9 19 t o 2 0 20 t o 2 1 21 t o 2 2 22 t o 2 3 23 t o 2 4 24 t o 2 5 Po p u l a t i o n G r o w t h Y e a r o v e r Y e a r 1990-2000growth 94,000 14 Regional Outlook--Persons 0 2 4 6 8 10 12 14 16 90 t o 9 1 91 t o 9 2 92 t o 9 3 93 t o 9 4 94 t o 9 5 95 t o 9 6 96 t o 9 7 97 t o 9 8 98 t o 9 9 99 t o 0 0 00 t o 0 1 01 t o 0 2 02 t o 0 3 03 t o 0 4 04 t o 0 5 05 t o 0 6 06 t o 0 7 07 t o 0 8 08 t o 0 9 09 t o 1 0 10 t o 1 1 11 t o 1 2 12 t o 1 3 13 t o 1 4 14 t o 1 5 15 t o 1 6 16 t o 1 7 17 t o 1 8 18 t o 1 9 19 t o 2 0 20 t o 2 1 21 t o 2 2 22 t o 2 3 23 t o 2 4 24 t o 2 5 Po p u l a t i o n G r o w t h Y e a r o v e r Y e a r 2005-2015No Action +56,000 FAFB+ED +53,000Total +94% faster1990-2000growth 94,000 Appendix C46 15 0 50 100 150 200 250 300 350 400 19 9 0 19 9 1 19 9 2 19 9 3 19 9 4 19 9 5 19 9 6 19 9 7 19 9 8 19 9 9 20 0 0 20 0 1 20 0 2 20 0 3 20 0 4 20 0 5 20 0 6 20 0 7 20 0 8 20 0 9 20 1 0 20 1 1 20 1 2 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 Em p l o y m e n t ( t h o u s a n d s ) Spokane Employment Kootenai Employment Kootenai & Spokane Employment 16 Kootenai & Spokane Population 0 100 200 300 400 500 600 700 800 19 9 0 19 9 1 19 9 2 19 9 3 19 9 4 19 9 5 19 9 6 19 9 7 19 9 8 19 9 9 20 0 0 20 0 1 20 0 2 20 0 3 20 0 4 20 0 5 20 0 6 20 0 7 20 0 8 20 0 9 20 1 0 20 1 1 20 1 2 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 Po p u l a t i o n ( t h o u s a n d s ) Spokane Population Kooteani Population Appendix C47 17 Degree Day Forecasts • Usage normalization – Heating Degree Days – Cooling Degree Days • Base Case Forecast at 96% of Normal 18 Spokane NWS Calendar Year Degree Days 122% 88% 136% 44% 135% 66% 96%99% 177% 98% 81% 117% 108% 147% 108% 98%100% 92% 108% 93% 93% 110% 95% 87%94% 106%100% 100%93%98% 0% 20% 40% 60% 80% 100% 120% 140% 160% 180% 200% 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 Average CDD Percent of Normal HDD Percent of Normal Appendix C48 19 July 2004 NOAA Climate Prediction Center 20 Price Forecasts •Electric Price Forecasts – In 2005 – assumed 14% Idaho, 5% Washington – Out years – assumed 8% at 4 year intervals •Natural Gas Price Forecasts – Retail – assumed 16% Idaho, 14% Washington – Cost of Gas – used Nymex index 7/1/04 through 2006, projected at Global Insight escalation afterward •Underlying Inflation – GDP Deflator from Global Insight Forecast – 20 year average is 2.9% Appendix C49 21 Avista Corp. Natural Gas Cost Forecasts 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00 1995 1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 Do l l a r s p e r D t h AECO Sumas Rockies Avista(50-25-25-0) 22 Avista Corp. Natural Gas Cost Forecasts 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00 1995 1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 Do l l a r s p e r D t h AECO Sumas Rockies Avista(50-25-25-0)Avista (constant 2005$) Appendix C50 23 Avista Corp. Natural Gas Cost Forecasts 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00 1995 1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 Do l l a r s p e r D t h AECO Sumas Rockies Avista(50-25-25-0)Avista (constant 2005$)Poly. (Avista(50-25-25-0)) 24 Results Base Case 2005 Forecast Appendix C51 25 Avista Customer Forecasts F2005 WA-ID Net-New Customer Forecast Residential Schedule 1 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 Ne t N e w C u s t o m e r s Washington-Electric 1,879 1,066 3,397 2,240 1,146 1,599 1,350 2,007 3,092 3,475 3,858 4,000 4,200 4,400 4,500 4,500 4,200 3,900 3,700 3,400 Idaho-Electric 2,172 849 2,116 1,320 1,234 956 994 1,240 1,851 2,375 2,642 2,800 2,900 3,000 3,000 3,000 2,950 2,900 2,400 2,200 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 26 Avista Customer Forecasts 200,000 250,000 300,000 350,000 400,000 450,000 500,000 1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 Ele c t r i c C u s t o m e r s Residential Commercial Industrial Street Lights 2005-2015 2.2%, 2005-2025 1.8% Appendix C52 27 Electric Use Per Customer 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 14,000 14,500 15,000 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Ki l o w a t t h o u r s p e r Y e a r 50,000 55,000 60,000 65,000 70,000 75,000 80,000 85,000 90,000 95,000 100,000 Residential Elect UPC Commercial Elec UPC 28 2005 ELECTRIC RETAIL SALES FORECAST (96% of Normal HDD) 0 1,000,000,000 2,000,000,000 3,000,000,000 4,000,000,000 5,000,000,000 6,000,000,000 7,000,000,000 8,000,000,000 9,000,000,000 10,000,000,000 11,000,000,000 12,000,000,000 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 calendar year PotlatchGeneration Street Lights Industrial Commercial Residential <------------------ forecast ------------------------------------------------------------> actual 2005-2010 growth rate = 2.7%, 2005-2015 growth rate =2.5% 6 mo. actual, 6 mo. forecast Appendix C53 29 Detailed Forecast Example Customer Bills kWh 2004 Residential ResidentialJAN186,129 274,940,054 FEB 186,120 228,408,122 MAR 186,014 205,886,320 APR 185,918 169,031,735 MAY 185,446 148,732,691 JUN 185,440 140,271,521 JUL 186,103 144,032,921 AUG 186,465 171,729,824 SEP 186,883 164,226,084 OCT 188,057 157,548,927 NOV 188,920 169,365,396 DEC 189,559 249,456,620 ANNUAL 186,755 2,223,630,215 Schedule 1 Customer Bills kWh WASHINGTON 2005 Residential ResidentialJAN 189,629 276,109,356 FEB 189,620 229,009,393 MAR 189,614 216,747,162 APR 189,418 178,171,171 MAY 188,046 153,164,092 JUN 188,340 143,102,482 JUL 189,403 148,052,799 AUG 190,165 176,888,810 SEP 190,483 169,063,531 OCT 191,757 162,255,171 NOV 192,720 174,499,789 DEC 193,359 257,001,933 ANNUAL 190,213 2,284,065,688 Customer Bills kWh2006 Residential ResidentialJAN 193,229 282,757,893 FEB 193,320 234,645,377 MAR 193,414 222,196,384 APR 193,318 182,748,804 MAY 191,346 156,631,213 JUN 192,140 146,719,706 JUL 193,403 151,935,422 AUG 194,265 181,606,085 SEP 194,483 173,476,807 OCT 195,857 166,553,008 NOV 196,720 179,012,228 DEC 197,359 263,630,101 ANNUAL 194,071 2,341,913,026 Schedule 1 1997 171,925 2,130,312,545 WASHINGTON 1998 175,322 2,138,822,255 1999 177,562 2,168,321,535 2000 178,708 2,160,945,957 2001 180,306 2,159,678,050 2002 181,656 2,136,771,135 2003 183,663 2,179,428,895 2004 186,755 2,223,630,215 2005 190,213 2,284,065,688 2006 194,071 2,341,913,026 2007 198,071 2,342,378,542 2008 202,271 2,404,007,745 2009 206,671 2,468,583,580 2010 211,171 2,534,945,495 2011 215,671 2,601,909,315 2012 219,871 2,599,527,552 2013 223,771 2,658,865,274 2014 227,471 2,716,343,087 2015 230,871 2,770,728,851 Customer Bills kWh2004 Residential ResidentialJAN89,987 129,609,729 FEB 90,069 109,259,642 MAR 90,099 95,008,145 APR 90,089 80,901,886 MAY 89,908 70,626,910 JUN 89,667 66,183,041 JUL 90,876 74,141,475 AUG 90,686 77,017,657 SEP 90,942 75,189,889 OCT 91,217 71,877,797 NOV 91,429 78,466,745 DEC 92,055 116,915,596 ANNUAL 90,585 1,045,198,512 Schedule 1 Customer Bills kWh IDAHO 2005 Residential ResidentialJAN 92,087 126,422,976 FEB 92,069 99,419,306 MAR 92,299 97,442,150 APR 92,189 83,876,301 MAY 91,808 71,758,976 JUN 91,567 76,517,893 JUL 93,676 74,897,347 AUG 93,386 77,724,494 SEP 93,442 75,711,726 OCT 93,917 72,525,254 NOV 94,229 79,252,382 DEC 94,855 118,062,335 ANNUAL 92,960 1,053,611,140 Customer Bills kWh2006 Residential ResidentialJAN 94,687 127,392,576 FEB 94,569 100,076,515 MAR 94,799 98,079,827 APR 94,589 84,338,695 MAY 94,008 72,008,969 JUN 93,767 76,789,195 JUL 96,476 75,593,327 AUG 96,186 78,453,816 SEP 96,242 76,420,827 OCT 96,817 73,269,419 NOV 97,229 80,140,055 DEC 97,855 119,360,392 ANNUAL 95,602 1,061,923,613 Schedule 1 1997 72,120 874,810,875 IDAHO 1998 73,910 880,832,795 1999 83,856 1,000,889,508 2000 85,544 1,013,145,552 2001 86,500 982,180,253 2002 87,494 994,626,457 2003 88,734 1,004,247,603 2004 90,585 1,045,198,512 2005 92,960 1,053,611,140 2006 95,602 1,061,923,613 2007 98,402 1,082,095,075 2008 101,302 1,119,555,367 2009 104,302 1,158,473,902 2010 107,302 1,197,753,633 2011 110,302 1,237,397,200 2012 113,252 1,257,786,175 2013 116,152 1,277,093,879 2014 118,552 1,309,999,343 2015 120,752 1,340,980,885 Customer Bills kWh 2004 Commercial Industrial Commercial IndustrialJAN379 229 1,245,004 1,553,351 FEB 382 232 1,285,056 1,552,317 MAR 380 229 1,426,908 1,508,680 APR 381 228 1,328,123 1,687,681 MAY 379 228 1,618,864 2,036,718 JUN 379 226 1,588,999 2,063,535 JUL 381 232 2,510,707 3,096,872 AUG 386 232 2,998,039 3,935,146 SEP 383 232 2,671,042 3,274,743 OCT 385 232 1,778,556 2,482,806 NOV 385 233 902,047 1,697,417 DEC 384 233 993,073 1,517,858 ANNUAL 382 231 20,346,419 26,407,123 Schedule 31 Customer Bills kWh IDAHO 2005 Commercial Industrial Commercial IndustrialJAN 389 231 1,305,951 1,859,042 FEB 392 234 1,184,250 1,524,305 MAR 390 231 1,119,732 1,533,620 APR 391 230 1,359,875 1,357,121 MAY 389 230 1,569,395 1,545,340 JUN 389 228 1,721,676 2,295,826 JUL 391 234 2,576,605 3,123,569 AUG 396 234 3,075,709 3,969,069 SEP 393 234 2,740,782 3,302,973 OCT 395 234 1,824,752 2,504,210 NOV 395 235 925,477 1,711,987 DEC 394 235 1,018,934 1,530,887 ANNUAL 392 233 20,423,139 26,257,949 Customer Bills kWh2006 Commercial Industrial Commercial IndustrialJAN 399 234 1,339,523 1,883,186 FEB 402 237 1,214,461 1,543,848 MAR 400 234 1,148,443 1,553,537 APR 401 233 1,394,655 1,374,823 MAY 399 233 1,609,740 1,565,496 JUN 399 231 1,765,935 2,326,034 JUL 401 237 2,642,503 3,163,614 AUG 406 237 3,153,378 4,019,955 SEP 403 237 2,810,522 3,345,319 OCT 405 237 1,870,949 2,536,315 NOV 405 238 948,907 1,733,842 DEC 404 238 1,044,795 1,550,430 ANNUAL 402 236 20,943,810 26,596,399 Schedule 31 1997 169 188 9,568,640 25,726,978 IDAHO 1998 189 192 12,955,525 27,186,518 1999 240 216 15,123,762 27,611,743 2000 297 245 14,593,633 28,079,935 2001 318 239 15,707,157 26,644,719 2002 333 229 17,357,731 25,955,353 2003 359 230 19,538,696 28,741,733 2004 382 231 20,346,419 26,407,123 2005 392 233 20,423,139 26,257,949 2006 402 236 20,943,810 26,596,399 2007 412 239 21,464,800 26,935,206 2008 422 242 21,985,790 27,274,014 2009 432 245 22,506,780 27,612,821 2010 442 248 23,027,771 27,951,629 2011 452 251 23,548,761 28,290,437 2012 462 254 24,069,751 28,629,244 2013 472 257 24,590,742 28,968,052 2014 482 260 25,111,732 29,306,860 2015 492 263 25,632,722 29,645,667 30 Load (MW)F2005 744 672 744 720 744 720 744 740 720 744 720 744 Annual Avg Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 1997 929 1,098 1,035 952 878 832 786 845 918 815 854 1,071 1,071 1998 954 1,065 994 943 902 941 845 966 936 866 886 960 1,140 1999 988 1,076 1,075 1,020 950 917 933 971 991 904 933 982 1,117 2000 1,012 1,153 1,114 1,034 921 889 924 961 985 889 950 1,163 1,173 2001 964 1,147 1,110 975 905 862 868 911 956 864 911 957 1,114 2002 994 1,095 1,072 1,040 929 898 950 1,018 953 891 968 1,034 1,090 2003 1,013 1,087 1,076 991 926 900 968 1,056 997 934 957 1,111 1,161 2004 1,029 1,194 1,108 987 925 900 963 1,020 1,057 956 1,016 1,044 1,184 2005 1,067 1,226 1,180 1,107 985 928 927 1,048 1,087 984 1,045 1,073 1,219 2006 1,099 1,262 1,211 1,139 1,014 955 955 1,081 1,121 1,018 1,079 1,106 1,258 2007 1,122 1,289 1,235 1,162 1,035 975 975 1,102 1,144 1,041 1,101 1,127 1,284 2008 1,152 1,325 1,267 1,193 1,064 1,001 1,002 1,129 1,174 1,070 1,129 1,156 1,319 2009 1,185 1,365 1,302 1,227 1,095 1,030 1,031 1,160 1,208 1,103 1,161 1,187 1,358 2010 1,215 1,401 1,334 1,257 1,123 1,055 1,057 1,188 1,238 1,133 1,189 1,216 1,393 2011 1,246 1,439 1,367 1,289 1,153 1,083 1,085 1,217 1,270 1,164 1,219 1,246 1,429 2012 1,270 1,469 1,393 1,314 1,175 1,104 1,106 1,239 1,294 1,188 1,242 1,269 1,458 2013 1,296 1,500 1,421 1,340 1,200 1,126 1,129 1,263 1,320 1,214 1,267 1,293 1,488 2014 1,323 1,533 1,450 1,368 1,225 1,150 1,153 1,289 1,348 1,241 1,293 1,319 1,520 2015 1,354 1,570 1,482 1,400 1,254 1,177 1,180 1,317 1,379 1,272 1,322 1,349 1,555 2016 1,379 1,600 1,509 1,425 1,278 1,198 1,202 1,340 1,404 1,297 1,346 1,372 1,585 2017 1,395 1,619 1,526 1,441 1,293 1,212 1,216 1,355 1,420 1,312 1,361 1,387 1,603 2018 1,417 1,646 1,550 1,464 1,314 1,231 1,235 1,376 1,443 1,335 1,382 1,409 1,629 2019 1,447 1,682 1,581 1,495 1,342 1,257 1,262 1,403 1,473 1,364 1,410 1,437 1,664 2020 1,472 1,713 1,608 1,521 1,366 1,279 1,284 1,427 1,499 1,389 1,434 1,461 1,694 2021 1,499 1,745 1,636 1,548 1,391 1,302 1,307 1,452 1,526 1,416 1,460 1,486 1,725 2022 1,517 1,767 1,656 1,567 1,408 1,318 1,323 1,469 1,544 1,434 1,477 1,504 1,746 2023 1,549 1,805 1,689 1,599 1,438 1,346 1,351 1,498 1,576 1,465 1,507 1,534 1,783 2024 1,577 1,839 1,719 1,628 1,464 1,370 1,376 1,524 1,604 1,493 1,534 1,561 1,816 2025 1,605 1,873 1,750 1,657 1,491 1,395 1,401 1,551 1,633 1,522 1,561 1,588 1,849 Avista Utilities Native Load Appendix C54 31 Avista Utilities Native Peak Demand Calendar Operating Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 1997 1,512 1,508 1,391 1,286 1,228 1,115 1,019 1,202 1,289 1,122 1,146 1,403 1,373 1998 1,665 1,578 1,575 1,255 1,195 1,251 1,249 1,164 1,521 1,422 1,317 1,246 1,296 1,663 1999 1,436 1,666 1,357 1,379 1,300 1,209 1,213 1,338 1,405 1,402 1,175 1,232 1,308 1,434 2000 1,570 1,475 1,458 1,474 1,301 1,262 1,147 1,308 1,454 1,396 1,183 1,254 1,492 1,561 2001 1,519 1,566 1,474 1,490 1,329 1,209 1,243 1,228 1,382 1,370 1,169 1,175 1,380 1,429 2002 1,457 1,452 1,388 1,362 1,398 1,180 1,149 1,376 1,457 1,335 1,197 1,360 1,337 1,412 2003 1,510 1,458 1,393 1,408 1,258 1,221 1,179 1,321 1,487 1,400 1,332 1,323 1,432 1,509 2004 1,779 1,779 1,766 1,434 1,366 1,177 1,121 1,391 1,514 1,501 1,275 1,352 1,389 1,566 2005 1,622 1,622 1,619 1,562 1,477 1,315 1,243 1,308 1,549 1,538 1,311 1,389 1,425 1,611 2006 1,669 1,669 1,666 1,602 1,518 1,353 1,278 1,344 1,590 1,582 1,354 1,432 1,467 1,660 2007 1,702 1,702 1,699 1,632 1,546 1,379 1,302 1,369 1,616 1,610 1,381 1,459 1,494 1,692 2008 1,748 1,748 1,745 1,672 1,585 1,415 1,335 1,402 1,651 1,649 1,419 1,495 1,530 1,736 2009 1,799 1,799 1,796 1,717 1,628 1,454 1,371 1,439 1,690 1,691 1,461 1,535 1,570 1,785 2010 1,844 1,844 1,841 1,757 1,666 1,490 1,404 1,472 1,725 1,729 1,498 1,571 1,606 1,829 2011 1,891 1,891 1,889 1,798 1,707 1,527 1,438 1,507 1,762 1,769 1,537 1,608 1,643 1,875 2012 1,928 1,928 1,926 1,831 1,738 1,556 1,464 1,533 1,790 1,800 1,568 1,637 1,672 1,911 2013 1,968 1,968 1,965 1,866 1,771 1,587 1,493 1,562 1,820 1,833 1,600 1,668 1,703 1,949 2014 2,010 2,010 2,007 1,903 1,807 1,619 1,523 1,593 1,852 1,868 1,635 1,701 1,736 1,990 2015 2,056 2,056 2,053 1,943 1,846 1,655 1,556 1,626 1,888 1,906 1,673 1,738 1,773 2,034 2016 2,094 2,094 2,091 1,977 1,878 1,685 1,583 1,654 1,917 1,938 1,704 1,768 1,803 2,071 2017 2,118 2,118 2,115 1,998 1,898 1,704 1,601 1,672 1,936 1,958 1,724 1,787 1,822 2,094 2018 2,153 2,153 2,150 2,028 1,928 1,730 1,625 1,697 1,962 1,987 1,752 1,814 1,849 2,128 2019 2,197 2,197 2,194 2,067 1,965 1,765 1,657 1,729 1,996 2,024 1,789 1,849 1,884 2,170 2020 2,236 2,236 2,233 2,102 1,998 1,796 1,685 1,757 2,026 2,057 1,821 1,880 1,915 2,208 2021 2,277 2,277 2,274 2,137 2,033 1,827 1,715 1,787 2,057 2,091 1,854 1,912 1,947 2,248 2022 2,305 2,305 2,302 2,162 2,056 1,849 1,735 1,807 2,079 2,115 1,877 1,934 1,969 2,275 2023 2,352 2,352 2,349 2,204 2,097 1,886 1,769 1,842 2,116 2,154 1,916 1,971 2,006 2,321 2024 2,395 2,395 2,392 2,242 2,133 1,920 1,800 1,873 2,148 2,190 1,952 2,005 2,040 2,362 2025 2,439 2,439 2,436 2,280 2,170 1,954 1,831 1,905 2,182 2,227 1,988 2,039 2,074 2,405 Appendix C55 Future Resource Future Resource RequirementsRequirements 2005 Integrated Resource Plan Second Technical Advisory Committee Meeting August 4, 2004 Jason Fletcher Update on Coyote Springs 2Update on Coyote Springs 2 • The Confidentiality Agreement and Non-Binding Letter of Intent have been signed by both parties. • The Asset Purchase and Sale Agreement is currently being negotiated. It is expected to be completed by the end of 2004. • 100% of Coyote Springs 2 will been included in the 2005 Integrated Resource Plan. Appendix C56 Future Resource RequirementsFuture Resource Requirements • The need for new resources is determined by the balance (imbalance) of expected loads and resources. • Energy and capacity values for expected loads and resources are tabulated for twenty years and included in Planning L&R’s. • Expected deficit years are as follows… - Energy – 2010 - Capacity – 2009 (?) Confidence Interval PlanningConfidence Interval Planning MEAN 10%10% 80% CI TWO-TAIL TEST Appendix C57 Confidence Interval PlanningConfidence Interval Planning MEAN 10% 90% CI ONE-TAIL TEST Long-Term Energy Load and Resource Tabulation (aMW) CONFIDENTIAL Last Updated July 30, 2004 Notes 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014REQUIREMENTSSystem Load 1 (1,008) (1,041) (1,063) (1,093) (1,126) (1,156) (1,187) (1,212) (1,237) (1,265) Contracts Out 2 (13) (11) (11) (11) (11) (9) (9) (8) (8) (8) WNP-3 Obligation 3 (31) (31) (31) (31) (31) (31) (31) (31) (31) (31) Confidence Interval 4 (163) (160) (160) (160) (159) (155) (155) (151) (151) (151) Total Requirements (1,215) (1,243) (1,265) (1,296) (1,327) (1,351) (1,382) (1,402) (1,428) (1,455) RESOURCESHydro 5 532 511 511 511 505 481 477 461 460 459 Contracts In 6 167 184 186 186 186 185 79 64 64 58 Base Load Thermals 7 241 234 234 242 232 236 240 235 234 238 Gas Dispatch Units 8 295 284 294 279 294 284 294 279 294 284 Peaking Units 9 139 135 138 138 137 134 138 138 137 138 Total Resources 1,374 1,349 1,364 1,356 1,355 1,320 1,229 1,177 1,189 1,178 Surplus (Deficit) 159 106 99 61 28 (31) (153) (225) (238) (276) ABSENT MIRANT SHARE OF CS2Generation Reduction 10 (133) (128) (133) (125) (133) (128) (133) (125) (133) (128) Net Position 27 (22) (34) (64) (105) (159) (285) (350) (371) (404) Energy Loads & Resources Energy Loads & Resources (aMW)(aMW) Appendix C58 Energy L&R Energy L&R ––2003 vs. 2005 IRP2003 vs. 2005 IRP 0 200 400 600 800 1,000 1,200 1,400 1,600 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Av e r a g e M e g a w a t t s Peakers Gas Dispatch Contracts Hydro Base Thermal Load w/ CI Load2003 IRP 2005 IRP 0 200 400 600 800 1,000 1,200 1,400 1,600 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Av e r a g e M e g a w a t t s 50% CS2 Peakers Gas Dispatch Contracts Hydro Base Thermal Load w/ CI Load2003 IRP 2005 IRP Energy L&R Energy L&R ––What’s Changed?What’s Changed? • Load Forecast • Contracts - Haleywest - Nichol’s Pumping - Potlatch - Upriver • 60-Year Hydro Calculation • Grant Contract Estimates • Northeast Emissions Limit • Mirant Share of Coyote Springs 2 99 aMW in 201499 aMW in 2014 -6 aMW-6 aMW -2 aMW-2 aMW 4 aMW4 aMW -12 aMW-12 aMW -16 aMW in 2014-16 aMW in 2014 -43 aMW-43 aMW 6 aMW6 aMW 133 aMW133 aMW Appendix C59 Energy L&R Energy L&R ––Annual to QuarterlyAnnual to Quarterly 0 200 400 600 800 1,000 1,200 1,400 1,600 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Av e r a g e M e g a w a t t s Base Thermal Hydro Contracts Gas Dispatch Peakers Load Load w/ CI 0 200 400 600 800 1,000 1,200 1,400 1,600 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Av e r a g e M e g a w a t t s Base Thermal Hydro Contracts Gas Dispatch Peakers 50% CS2 Load Load w/ CI 0 200 400 600 800 1,000 1,200 1,400 1,600 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Av e r a g e M e g a w a t t s Base Thermal Hydro Contracts Gas Dispatch Peakers 50% CS2 Load Load w/ CI Energy L&R Energy L&R ––Annual to QuarterlyAnnual to Quarterly Appendix C60 Long-Term Peak Load and Resource Tabulation (MW) CONFIDENTIAL Last Updated July 30, 2004 Notes 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014REQUIREMENTSSystem Load 1 (1,500) (1,598) (1,637) (1,674) (1,734) (1,779) (1,813) (1,849) (1,903) (1,945) Contracts Out 2 (170) (166) (166) (166) (166) (161) (159) (159) (159) (159) Hydro Reserves (5%) 3 (61) (59) (58) (59) (58) (55) (53) (53) (53) (53) Thermal Reserves (7%) 4 (48) (48) (48) (48) (48) (48) (48) (48) (48) (48) Total Requirements (1,779) (1,871) (1,910) (1,947) (2,007) (2,044) (2,074) (2,110) (2,164) (2,205) RESOURCES Hydro 5 975 991 930 1,003 935 925 993 893 884 883 Contracts In 6 199 217 220 219 220 218 97 97 98 98 Base Load Thermals 7 275 275 275 275 275 275 275 275 275 275 Gas Dispatch Units 8 308 310 305 310 309 305 310 310 305 309 Peaking Units 9 243 243 243 243 243 243 243 243 243 243 Total Resources 2,000 2,035 1,973 2,049 1,982 1,967 1,917 1,817 1,805 1,808 Surplus (Deficit) 220 165 63 102 (25) (77) (157) (293) (359) (398) ABSENT MIRANT SHARE OF CS2Generation Reduction 10 (138) (139) (139) (139) (139) (139) (139) (139) (139) (139) Net Surplus (Deficit) 82 26 (76) (37) (164) (216) (296) (432) (498) (536) Capacity Loads & Resources Capacity Loads & Resources (MW)(MW) Long-Term Peak Load and Resource Tabulation (MW) CONFIDENTIAL Last Updated July 30, 2004 Notes 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014REQUIREMENTSSystem Load 1 (1,500) (1,598) (1,637) (1,674) (1,734) (1,779) (1,813) (1,849) (1,903) (1,945) Contracts Out 2 (170) (166) (166) (166) (166) (161) (159) (159) (159) (159) Hydro Reserves (5%) 3 (61) (59) (58) (59) (58) (55) (53) (53) (53) (53) Thermal Reserves (7%) 4 (48) (48) (48) (48) (48) (48) (48) (48) (48) (48) Total Requirements (1,779) (1,871) (1,910) (1,947) (2,007) (2,044) (2,074) (2,110) (2,164) (2,205) RESOURCESHydro 5 975 991 930 1,003 935 925 993 893 884 883 Contracts In 6 199 217 220 219 220 218 97 97 98 98 Base Load Thermals 7 275 275 275 275 275 275 275 275 275 275 Gas Dispatch Units 8 308 310 305 310 309 305 310 310 305 309 Peaking Units 9 243 243 243 243 243 243 243 243 243 243 Total Resources 2,000 2,035 1,973 2,049 1,982 1,967 1,917 1,817 1,805 1,808 Surplus (Deficit) 220 165 63 102 (25) (77) (157) (293) (359) (398) ABSENT MIRANT SHARE OF CS2Generation Reduction 10 (138) (139) (139) (139) (139) (139) (139) (139) (139) (139) Net Surplus (Deficit) 82 26 (76) (37) (164) (216) (296) (432) (498) (536) Capacity Loads & Resources Capacity Loads & Resources (MW)(MW) Planning Reserve Margin 20% 15% 9% 11% 4% -2% -3% -10% -12% -14% Appendix C61 Capacity L&R Capacity L&R ––2003 vs. 2005 IRP2003 vs. 2005 IRP 0 500 1,000 1,500 2,000 2,500 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Me g a w a t t s Peakers Gas Dispatch Contracts Hydro Base Thermal Load w/ Res. Load2003 IRP 2005 IRP 0 500 1,000 1,500 2,000 2,500 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Me g a w a t t s 50% CS2 Peakers Gas Dispatch Contracts Hydro Base Thermal Load w/ Res. Load2003 IRP 2005 IRP Appendix C62 800 1,000 1,200 1,400 1,600 1,800 2,000 20 0 5 20 0 6 20 0 7 20 0 8 20 0 9 20 1 0 20 1 1 20 1 2 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 Av e r a g e M e g a w a t t s Average Load Forecast ComparisonAverage Load Forecast Comparison 2005 Forecast(07-27-2004) 2004 Forecast (07-31-2004) 2003 Forecast (08-27-2002) AARG 2003 2004 2005 3.4% 2.4% 2.2% 1,400 1,600 1,800 2,000 2,200 2,400 2,600 2,800 3,000 20 0 5 20 0 6 20 0 7 20 0 8 20 0 9 20 1 0 20 1 1 20 1 2 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 Me g a w a t t s Peak Load Forecast ComparisonPeak Load Forecast Comparison 2004 Forecast(07-31-2004) 2003 Forecast(08-27-2002) 2005 Forecast(07-27-2004) AARG 2003 2004 2005 3.3% 2.3% 2.1% Appendix C63 1 Overview ofOverview of Natural Gas ForecastNatural Gas Forecast 2005 Integrated Resource Plan Third Technical Advisory Committee Meeting January 25, 2005 James Gall 2 IntroductionIntroduction Historical gas prices Proposed gas forecast Review of peer forecasts Why are gas prices are important? Historical electric prices Regression analysis for electric and gas prices How gas prices affect prices/costs in Aurora Appendix C64 3 Recent Natural Gas PricesRecent Natural Gas Prices Annual Average Prices (Nominal Dollars)Annual Average Prices (Nominal Dollars) 0.00 1.00 2.00 3.00 4.00 5.00 6.00 7.00 1998 1999 2000 2001 2002 2003 2004 $/ M M B t u Henry Hub Sumas Malin 4 Recent Volatility of the Forward MarketRecent Volatility of the Forward Market 2005 Annual Average Prices Traded at Malin in 20042005 Annual Average Prices Traded at Malin in 2004 Statistics: -Mean: $5.71 -Median: $5.75 -Mode: $4.90 -Min: $4.68-Max $7.50 -Standard Deviation: $0.65 -Variance: 0.42 -Skewness: 0.43 -Kurtosis: 3.94 Pro b a b l i l i t y $/MMBtu 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0 <>5.0%90.0% 4.767 6.905 Appendix C65 5 Recent Volatility of the Forward MarketRecent Volatility of the Forward Market January 2005 Average Prices Traded at Malin in 2004January 2005 Average Prices Traded at Malin in 2004 Statistics: -Mean: $6.38 -Median: $6.32 -Mode: $5.76 -Min: $5.20-Max $9.23 -Standard Deviation: $0.81 -Variance: 0.65 -Skewness: 1.22 -Kurtosis: 4.48 Pro b a b l i l i t y $/MMBtu 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 5.0 5.5 6.0 6.5 7.0 7.5 8.0 8.5 9.0 9.5 <>5.0% 5.0%90.0% 5.397 8.031 6 - 2.00 4.00 6.00 8.00 10.00 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 $/M M B t u Henry Hub Sumas Malin Forecasted Natural Gas PricesForecasted Natural Gas Prices Annual Average Prices (Nominal Dollars)Annual Average Prices (Nominal Dollars) Historic Forecast Key Assumptions • July 2004 Forward Price Curves for 2005 through 2007 • 2005- 07: -7.1% • Avg. Growth Rates – Based on July Global Insights forecast • 2007- 09: 1.9% • 2010- 20: 3.2% • 2020- 30: 3.8% New Escalation Rates New Escalation Rates Available in AprilAvailable in April Appendix C66 7 - 2.00 4.00 6.00 8.00 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 $/ M M B t u Henry Hub Sumas Malin Forecasted Natural Gas PricesForecasted Natural Gas Prices Annual Average Prices (2005 Dollars)Annual Average Prices (2005 Dollars) Historic Forecast 8 How Does Our Forecast Compare with Others at How Does Our Forecast Compare with Others at Henry Hub?Henry Hub? EIA Wellhead- Annual Energy Outlook 2005 Early Release (Avg. price for lower 48 states) NYMEX- www.NYMEX.com on 12/30/2004 - 2.00 4.00 6.00 8.00 10.00 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 $/ M M B t u EIA Wellhead NYMEX 2004 Idaho IRP 2005 Avista IRP RW Beck Appendix C67 9 How Does Our Forecast Compare with Others at How Does Our Forecast Compare with Others at Malin?Malin? 0.00 2.00 4.00 6.00 8.00 10.00 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 $/ M M B t u 2005 Avista IRP 2005 PacifiCorp IRP "West"2003 Avista IRP 10 How Does Our Forecast Compare with Others at How Does Our Forecast Compare with Others at Sumas?Sumas? NWPPC- “Draft” of 5thPower Plan 0.00 2.00 4.00 6.00 8.00 10.00 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 $/ M M B t u 2005 PacifiCorp IRP "West"2005 Avista IRP 2004 Idaho IRP NWPPC- Medium NWPPC- Low NWPPC- High Appendix C68 11 Why are Gas Prices Important?Why are Gas Prices Important? Electric Market prices Power costs Build/buy decisions Type of resource 12 Historical MidHistorical Mid--C PricesC Prices - 10 20 30 40 50 60 70 80 90 100 Ma y - 9 6 No v - 9 6 Ma y - 9 7 No v - 9 7 Ma y - 9 8 No v - 9 8 Ma y - 9 9 No v - 9 9 Ma y - 0 0 No v - 0 0 Ma y - 0 1 No v - 0 1 Ma y - 0 2 No v - 0 2 Ma y - 0 3 No v - 0 3 Ma y - 0 4 No v - 0 4 $/ M W h - 100 200 300 400 500 600 Appendix C69 13 Regression AnalysisRegression Analysis Mid C Prices and Northwest Gas Markets (1996Mid C Prices and Northwest Gas Markets (1996--2004)2004) Mid C vs Malin R2 = 0.7454 - 100 200 300 400 500 600 - 5 10 15 20 25 Gas Prices ($/MMBtu) Mi d C P r i c e s ( $ / M W h ) Mid C vs Sumas R2 = 0.5767 - 100 200 300 400 500 600 - 5 10 15 20 25 Gas Prices ($/MMBtu) Mid C P r i c e s ( $ / M W h ) • 86% correlation between Malin Gas Prices and Mid C Electric Prices • 74% of the time a change to Malin Prices will have an effect on the Mid C Market • 76% correlation between Sumas Gas Prices and Mid C Electric Prices • 58% of the time a change to Sumas Prices will have an effect on the Mid C Market 14 2004 Daily NW Gas 2004 Daily NW Gas vs vs NW Electric Correlation by NW Electric Correlation by MonthMonth 0% 20% 40% 60% 80% 100% January Febr u a ry Marc h April May June July August Sept e m b e r October Novem b e r Dece m b e r Pe r c e n t C o r r e l a t i o n Malin vs Mid C Sumas vs Mid C Appendix C70 15 Change to Mid C Electric Market with +/Change to Mid C Electric Market with +/--$2 Gas $2 Gas Price VariationsPrice Variations--Example OnlyExample Only Avg. Range ~$32.00 - 10.00 20.00 30.00 40.00 50.00 60.00 70.00 80.00 Jan-06 Mar-06 May-06 Jul-06 Sep-0 6 Nov-06 Jan-07 Mar-07 May-07 Jul-07 Sep-07 Nov-07 Jan-08 Mar-08 May-08 Jul-08 Sep-0 8 Nov-08 $/M W h Low Base High 16 Regression AnalysisRegression Analysis Aurora Fuel Price Sensitivity Results (2006Aurora Fuel Price Sensitivity Results (2006--2008)2008) • 90% correlation between Malin Gas Prices and Northwest Electric Prices • 81% of the time a change to Malin Prices will have an effect on the Northwest Area Market • 97% correlation between Malin Gas Prices and Northern California Electric Prices• 93% of the time a change to Malin Prices will have an effect on the Northern California Area Market Malin Gas vs. NW Electric R2 = 0.8188 - 10.00 20.00 30.00 40.00 50.00 60.00 70.00 80.00 2 3 4 5 6 7 8 9 Malin Gas ($/MMBtu) No r t h w e s t E l e c t r i c ( $ / M W h ) Malin Gas vs N. CA Electric R2 = 0.9341 0.00 10.00 20.00 30.00 40.00 50.00 60.00 70.00 80.00 2 3 4 5 6 7 8 9 Malin Gas + 12¢ ($/MMBtu) No r t h e r n C a l i f o r n i a E l e c t r i c ( $ / M W h ) Appendix C71 17 Change to 2006 Northwest Resource Stack with Gas Change to 2006 Northwest Resource Stack with Gas Price VariationsPrice Variations--Example OnlyExample Only 0 40 80 120 160 200 $/M W h High Base Low 35.8 GW Hydro 40.5 GW Coal and Others CCCT/ Other Gas/ Co-Gen Oil/others Peakers 39 GW34 GW 18 ($10,000) ($5,000) $0 $5,000 $10,000 $15,000 $20,000 Jan- 06 Apr- 06 Jul- 06 Oct- 06 Jan- 07 Apr- 07 Jul- 07 Oct- 07 Jan- 08 Apr- 08 Jul- 08 Oct- 08 Th o u s a n d s o f D o l l a r s Low Base Case High Change to Avista’s Power Costs with Gas Price Change to Avista’s Power Costs with Gas Price VariationsVariations--Example OnlyExample Only Impact: $2.00 (~35%) increase/decrease in gas prices changes Avista’s annual power supply costs by ~11%. Spring months favor high prices because of increased market sales Appendix C72 19 Coal and Other FuelsCoal and Other Fuels These forecasts will be presented at the next TAC meeting 20 Gas Price SensitivitiesGas Price Sensitivities--What Types Should We Do?What Types Should We Do? Gas price variations will be tested during stochastic studies Should we study gas variations deterministically Percentage increase/decrease? Value increase/decrease? Scenario based? Others? Appendix C73 21 ConclusionsConclusions After 2009, inflation drives natural gas prices from today’s forward prices The proposed gas forecast tends to be higher than some peer forecasts, and lower than others Historical gas prices are correlated with the Northwest electric market when hydro/coal are not on the margin Aurora results indicate a higher correlation between gas and electric prices for the future A change in gas prices can have a large effect on the electric price and Avista’s power costs Appendix C74 Sustained Capacity and Sustained Capacity and Planning Margin ConceptsPlanning Margin Concepts 2005 Integrated Resource Plan Third Technical Advisory Committee Meeting January 25, 2005 Clint Kalich 2 Presentation Overview • What Is Sustained Capacity 3 • Why Capacity Methods Matter 4 • Comparison to Peak Forecasting 5 • Various Views of Historical Temperatures 6-7 • Various Views of Historical Loads 8-14 • Sustained Peak Calculations & Positions 2005/07/10 15-18 • Avista vs. FERC SMD 19-20 • Key Capacity Planning Questions 21 • Planning Margin Methods Summary 22 • Capacity Plan for 2005 IRP 23 Slide # Appendix C75 3 What Is Sustained Capacity • A Tabulation of Loads and Resources Over a Period(s) Exceeding the Traditional 1-Hour Definition of Peak • A Measure of Reliability • An Essential Concept of Utility Planning • A Recognition that Peak Loads Do Not Stress the System For Just One Hour – Especially important in energy-limited NW hydro system • The “Grey Area” Between Energy and Capacity Planning • An Event Which Occurs Infrequently • A Concept Parallel to “Planning Margins” 4 Why Capacity Methods Matter • Planning Method Defines Level of Capacity Required to Meet Load • Larger Capacity Margins Cost Customers More – Capital and fixed costs are built into rates • 100 MW ~ $35-50MM, or ~$5-$8MM per year – Offsetting operating revenues are limited • capacity resources generally are inefficient relative to energy resources and therefore operate for very few hours Appendix C76 5 Comparison to Peak Forecasting One Hour to Three Days, or MoreOne HourPeriod Actual ForecastActual Forecast Contracts Maximum Capability Reduced for Freeze (~ 60 MW) Maximum Capability Hydro Lowest Temps & Colstrip Reduced for Freeze (~ 30 MW) Average Temps Thermals Lowest Load on Record ~ 120-160 MW in 2005 Average Coldest Day Temp Peak Load Sustained Capacity Capacity L&RItem 6 Temp. Distribution (1889-2004) Spokane International Airport 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 -15 -10 -5 0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 daily average tem perature ob s e r v a t i o n s ( o f 4 2 , 0 9 3 ) Appendix C77 7 Temperature History (1989-04) Spokane International Airport (1 5 ) (1 0 ) (5 ) 0 5 1 0 1 5 2 0 2 5 0.0%0.1%0.2%0.3%0.4%0.4%0.5%0.6%0.7%0.8%0.9%1.0%1.0%1.1%1.2%1.3%1.4%1.5%1.6%1.7%1.7%1.8%1.9% p e rc e n t o f h o u rs de g r e e s F a r e n h e i t 1 -D a y 3 -D a y 1 -W e e k 2 -W e e k 8 Peak Load History (1989-04) Avista Total 0 50 100 150 200 250 300 350 400 450 525 575 625 675 725 775 825 875 925 975 1,025 1,075 1,125 1,175 1,225 1,275 1,325 1,375 1,425 1,475 1,525 1,575 daily load (aMW) ob s e r v a t i o n s ( o f 5 , 8 5 6 ) 95% below 1,166 aMW 99% below 1,270 aMW Appendix C78 9 Daily Versus Hourly Peaks 2004 Load 0 200 400 600 800 1000 1200 50 0 55 0 60 0 65 0 70 0 75 0 80 0 85 0 90 0 95 0 1, 0 0 0 1, 0 5 0 1, 1 0 0 1, 1 5 0 1, 2 0 0 1, 2 5 0 1, 3 0 0 1, 3 5 0 1, 4 0 0 1, 4 5 0 1, 5 0 0 1, 5 5 0 1, 6 0 0 1, 6 5 0 1, 7 0 0 1, 7 5 0 megawatts ob s e r v a t i o n s Daily Load Hourly Load 10 2004 Daily Load Duration Peak Day = 1,574 aMW Peak Hour = 1,766 MW 800 900 1,000 1,100 1,200 1,300 1,400 1,500 1,600 0.3%4.6%9.0% 13.4 % 17.8 % 22.1 % 26.5 % 30.9 % 35.2 % 39.6 % 44.0 % 48.4 % 52.7 % 57.1 % 61.5 % 65.8 % 70.2 % 74.6 % 79.0 % 83.3 % 87.7 % 92.1 % 96.4 % percent of hours lo a d ( a M W ) 95% of days below 1,206 aMW 99% of days below 1,350 aMW Appendix C79 11 2004 Peak Load and Temps 30 Highest Load Days 1,100 1,150 1,200 1,250 1,300 1,350 1,400 1,450 1,500 1,550 1,600 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 av e r a g e m e g a w a t t s -20 -10 0 10 20 30 40 50 60 70 80 de g r e e s F a r e n h e i t Temperature 12 Peak Load History (1989-04) Avista Total 1,100 1,150 1,200 1,250 1,300 1,350 1,400 1,450 1,500 1,550 1,600 0.0 % 0.2 % 0.4 % 0.6 % 0.8 % 1.0 % 1.2 % 1.5 % 1.7 % 1.9 % 2.1 % 2.3 % 2.5 % 2.7 % 2.9 % 3.1 % 3.3 % 3.5 % 3.7 % 3.9 % 4.1 % 4.3 % 4.5 % 4.7 % 4.9 % p ercen t o f h o u rs lo a d ( a M W ) 1-D ay 3-D ay 1-W eek 2-W eek Appendix C80 13 Peak Load Shape Comparison 600 800 1,000 1,200 1,400 1,600 1,800 HR 1 HR 2 HR 3 HR 4 HR 5 HR 6 HR 7 HR 8 HR 9 HR 1 0 HR 1 1 HR 1 2 HR 1 3 HR 1 4 HR 1 5 HR 1 6 HR 1 7 HR 1 8 HR 1 9 HR 2 0 HR 2 1 HR 2 2 HR 2 3 HR 2 4 av e r a g e m e g a w a t t s 1-D ay 3-D ay 1-W eek 2-W eek W inter Sum m er 14 Summer Vs. Winter Peaks 75% 78% 80% 83% 85% 88% 90% 1 -Hour 4 -Hour 8 -Hour 12 -Hour 1-Day 3-Day 1 W eek 2 W eek av e r a g e m e g a w a t t s Appendix C81 15 Sustained Peak Estimate—2005 Sustained Peak Period L&R Calculation Comparison 2005 Peak Period Considered 1 -Hour 4 -Hour 8 -Hour 12 -Hour 24 -Hour 72 -Hour 168 -Hour 336 -Hour Load Peak Load (1,619) (1,598) (1,579) (1,542) (1,450) (1,377) (1,369) (1,175) 10% Contingency (162)(160)(158)(154)(145)(138)(137)(117) Load Subtotal (1,781) (1,758) (1,736) (1,696) (1,595) (1,515) (1,506) (1,292) Hydro Capability Hydro @ 90% CI 208 208 208 326 326 326 326 326 Hydro Storage 959 871 825 550 275 211 154 77 River Freeze Up (60)(60)(60)(60)(60)(60)(60)(60)Hydro Subtotal 1,107 1,019 973 816 541 477 419 342 Thermal Capability Coyote Springs II 308 308 308 308 308 308 308 308 Colstrip 222 222 222 222 222 222 222 222 Rathdrum 184 184 184 184 184 184 184 184Northeast 69 69 69 69 69 69 69 69Kettle Falls 62 62 62 62 62 62 62 62 Boulder Park 25 25 25 25 25 25 25 25 Fuel Delivery System Freeze Up (30)(30)(30)(30)(30)(30)(30)(30) Thermal Subtotal 839 839 839 839 839 839 839 839 ContractsNet Contracts 139 139 139 139 139 139 139 139 PGE Adjustment 0 0 0 25 38 46 105 105 PPM Wind @ 25% of Capacity 0 0 0 0 0 0 0 0 000 MW Spot Purchases 0 0 0 0 0 0 0 0Contracts Subtotal 139 139 139 164 177 185 245 245 Net Position 304 240 215 123 (38) (14) (3) 134 16 Sustained Peak Estimate—2007 Sustained Peak Period L&R Calculation Comparison 2007 Peak Period Considered 1 -Hour 4 -Hour 8 -Hour 12 -Hour 24 -Hour 72 -Hour 168 -Hour 336 -Hour Load Peak Load (1,699) (1,677) (1,656) (1,618) (1,521) (1,445) (1,436) (1,233) 10% Contingency (170)(168)(166)(162)(152)(145)(144)(123) Load Subtotal (1,869) (1,844) (1,822) (1,780) (1,673) (1,590) (1,580) (1,356) Hydro CapabilityHydro @ 90% CI 195 195 195 274 274 274 274 274 Hydro Storage 929 929 757 505 252 204 150 75 River Freeze Up (60)(60)(60)(60)(60)(60)(60)(60) Hydro Subtotal 1,064 1,064 892 718 466 417 364 289 Thermal CapabilityCoyote Springs II 308 308 308 308 308 308 308 308 Colstrip 222 222 222 222 222 222 222 222 Rathdrum 184 184 184 184 184 184 184 184Northeast 69 69 69 69 69 69 69 69Kettle Falls 62 62 62 62 62 62 62 62 Boulder Park 25 25 25 25 25 25 25 25 Fuel Delivery System Freeze Up (30)(30)(30)(30)(30)(30)(30)(30) Thermal Subtotal 839 839 839 839 839 839 839 839 ContractsNet Contracts 160 160 160 160 160 160 160 160 PGE Adjustment 0 0 0 25 38 46 105 105 PPM Wind @ 25% of Capacity 0 0 0 0 0 0 0 0 000 MW Spot Purchases 0 0 0 0 0 0 0 0Contracts Subtotal 160 160 160 185 198 206 266 266 Net Position 195 220 70 (37) (170) (127) (111) 38 Appendix C82 17 Sustained Peak Estimate—2010 Sustained Peak Period L&R Calculation Comparison 2010 Peak Period Considered 1 -Hour 4 -Hour 8 -Hour 12 -Hour 24 -Hour 72 -Hour 168 -Hour 336 -Hour Load Peak Load (1,841) (1,817) (1,795) (1,753) (1,648) (1,566) (1,556) (1,336) 10% Contingency (184)(182)(179)(175)(165)(157)(156)(134)Load Subtotal (2,026) (1,999) (1,974) (1,928) (1,813) (1,723) (1,712) (1,469) Hydro Capability Hydro @ 90% CI 131 131 131 184 184 184 184 184 Hydro Storage 948 948 685 456 228 196 147 73River Freeze Up (60)(60)(60)(60)(60)(60)(60)(60)Hydro Subtotal 1,019 1,019 756 580 352 319 270 197 Thermal Capability Coyote Springs II 308 308 308 308 308 308 308 308Colstrip 222 222 222 222 222 222 222 222Rathdrum 184 184 184 184 184 184 184 184 Northeast 69 69 69 69 69 69 69 69 Kettle Falls 62 62 62 62 62 62 62 62Boulder Park 25 25 25 25 25 25 25 25Fuel Delivery System Freeze Up (30)(30)(30)(30)(30)(30)(30)(30) Thermal Subtotal 839 839 839 839 839 839 839 839 ContractsNet Contracts 165 165 165 165 165 165 165 165PGE Adjustment 0 0 0 25 38 46 105 105 PPM Wind @ 25% of Capacity 0 0 0 0 0 0 0 0 000 MW Spot Purchases 0 0 0 0 0 0 0 0 Contracts Subtotal 165 165 165 190 203 211 271 271 Net Position (2) 25 (214) (319) (419) (353) (332) (162) 18 Avista Net Positions (500) (400) (300) (200) (100) 0 100 200 300 400 1 -Hour 4 -Hour 8 -Hour 12 -Hour 1-Day 3-Day 1 W eek 2 W eek av e r a g e m e g a w a t t s 2005 Net Position 2007 Net Position 2010 Net Position Appendix C83 19 Avista vs. FERC SMD 1 -Hour 4 -Hour 8 -Hour 12 -Hour 24 -Hour 72 -Hour 168 -Hour 336 -Hour 2005 Avista Criteria 345 281 256 129 (32) (9) 3 138 SMD - 12% 538 448 433 275 115 113 165 385 SMD - 15% 490 401 385 229 72 72 124 350 SMD - 18% 442 353 338 183 28 31 83 315 2007 Avista Criteria 212 237 87 (19) (153) (110) (94) 55 SMD - 12% 417 416 275 142 11 29 85 319 SMD - 15% 366 366 225 93 (35) (15) 42 282 SMD - 18% 315 315 175 45 (81) (58) (1) 245 2010 Avista Criteria 16 43 (197) (301) (402) (336) (314) (145) SMD - 12% 138 170 (88) (192) (307) (215) (142) 416 SMD - 15% 82 116 (142) (245) (357) (262) (189) 376 SMD - 18% 27 61 (196) (297) (406) (309) (235) 335 20 SMD Net Positions – 15% (500) (400) (300) (200) (100) 0 100 200 300 400 500 1 -Hour 4 -Hour 8 -Hour 12 -Hour 1-Day 3-Day 1 W eek 2 W eek av e r a g e m e g a w a t t s 2005 Net Position 2007 Net Position 2010 Net Position Appendix C84 21 Key Capacity Planning Questions • Which Sustained Period is Adequate • How Much Can/Should Avista Rely On The Market During Extreme Load Conditions • What Capacity Should Be Given to Wind • With Move To Gas-Fired Turbines, Will Gas Be Available To Meet Coincident Demands • How Will Federal Projects Act During a Cold Snap • What is the Significance of Transmission • Is LOLP a Better Method & How Would We Do LOLP 22 Planning Margin Methods Summary • FERC Standard Market Design – Carry between 12% & 18% of average peak day load – California has moved toward 15% • Loss of Load Probability • Sustained Capacity Evaluations • Avista Method For Calculating Planning Margin – 110% of Peak demand forecast – ~ 30 MW for Colstrip fuel handling – ~ 60 MW for river freeze-ups Appendix C85 23 Capacity Plan for the 2005 IRP • Rely On Historical Method Adopted in 1980s – ~ 250 MW over forecasted peak demand – Modestly better protection than FERC SMD • Build Resources To Meet Energy AND Capacity Needs—Consider Purchases if Appropriate • Encourage and Assist Regional Entities With Regional Capacity Planning Effort – e.g., NPCC, NWPP, BPA Appendix C86 1 2005 Load Forecast Scenarios Presented by Randy Barcus, Avista Corp. Chief Economist January 25, 2005 2 Forecast Discussion Points • Economic Forecast – Employment – Population – Scenario Options • Degree Days – Heating – Cooling • Prices – Electric--Retail – Natural Gas—Retail and Wholesale • Electric Base Case Results Appendix C87 3 Economic Forecast • Global Insight, Inc. Contract – National Outlook – Spokane County, Washington – Kootenai County, Idaho • Adjustments – Fairchild Air Force Base Assessment – Economic Development Initiatives • Allocation Scenario 4 Regional Economy • Risk to Growth (Low Scenario) – Military Base Realignment and Closure Process during 2005 indicates closure – Continued Meltdown in Manufacturing • Opportunity for Growth (High Scenario) – Base expands with new missions – University District, Airport Freight Hub, Technology Parks – Convention Center Tourism Expansion Appendix C88 5 Results High & Low Case 2005 Forecast 6 Avista High Customer Forecasts F2005 WA-ID High Case Net-New Customer Forecast Residential Schedule 1 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 199619971998199920002001200220032004200520062007200820092010201120122013201420152016201720182019202020212022202320242025 Ne t N e w C u s t o m e r s WA-E Base ID-E Base WA-E High ID-E High Appendix C89 7 Avista Low Customer Forecasts F2005 WA-ID Low Case Net-New Customer Forecast Residential Schedule 1 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 199619971998199920002001200220032004200520062007200820092010201120122013201420152016201720182019202020212022202320242025 Ne t N e w C u s t o m e r s WA-E Base ID-E Base WA-E Low ID-E Low 8 F2005 Avista Megawatthour Forecast Excluding Potlatch Lewiston 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 19971998199920002001200220032004200520062007200820092010201120122013201420152016201720182019202020212022 M e g a w a t t h o u r s F2005 High net F2005Final net F2005 Low Appendix C90 9 F2005 High-Low MW Variation Forecast Excluding Potlatch Lewiston -400 -300 -200 -100 0 100 200 300 400 Av e r a g e M W High MW Variation Low MW Variation High MW Variation - - 11 29 42 57 71 85 100 115 129 150 172 195 220 246 275 303 Low MW Variation - - (11) (29) (42) (57) (71) (85) (100) (115) (129) (150) (172) (195) (220) (246) (275) (303) 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Appendix C91 Future Resource Future Resource Requirements UpdateRequirements Update 2005 Integrated Resource Plan Third Technical Advisory Committee Meeting January 25, 2005 John Lyons Future Resource RequirementsFuture Resource Requirements • New resource requirements are determined by the net balance of expected loads and resources. • Energy and capacity values for expected loads and resources are calculated twenty years into the future and are included in Planning L&R’s. • Expected deficit years are as follows: - Energy – 2010 - Capacity – 2009 Appendix C92 Energy Loads & Resources Energy Loads & Resources (aMW) (aMW) LONG-TERM LOAD AND RESOURCES TABULATION—ENERGY (aMW) CONFIDENTIAL Last Updated January 13, 2005 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 REQUIREMENTS System Load (1,065) (1,098) (1,120) (1,151) (1,183) (1,213) (1,245) (1,269) (1,295) (1,322) (1,353) (1,378) Contract Obligations (62) (60) (60) (60) (60) (59) (58) (57) (57) (57) (57) (57) Total Requirements (1,127) (1,158) (1,181) (1,211) (1,244) (1,272) (1,303) (1,327) (1,352) (1,379) (1,410) (1,435) RESOURCES Contract Rights 283 292 295 294 295 294 189 171 172 164 162 162 Hydro 539 517 517 517 512 494 490 473 472 472 471 471 Base Load Thermals 236 224 224 237 221 226 235 225 224 237 225 224 Gas Dispatch Units 262 272 282 268 282 272 282 268 282 273 282 268 Total Resources 1,320 1,306 1,318 1,316 1,310 1,286 1,196 1,137 1,150 1,145 1,140 1,124 POSITION 193 147 137 105 67 14 (107) (190) (202) (234) (270) (311) CONTINGENCY PLANNING Confidence Interval (163) (160) (160) (160) (159) (155) (155) (151) (151) (151) (151) (151) WNP-3 Obligation (33) (33) (33) (33) (33) (33) (33) (33) (33) (33) (33) (33) Peaking Resources 146 142 145 145 145 141 145 145 144 146 146 142 CONTINGENCY NET POSITION 143 96 89 57 19 (33) (150) (229) (243) (273) (308) (353) Energy L&R Energy L&R ––Changes Since AugustChanges Since August • Contracts ~ 3 aMW Increase • Hydro ~ 7 aMW Increase • Peaking Units ~ 7 aMW Increase • Base Thermal ~ 5 aMW Decrease • Gas Dispatch ~ 12 aMW Decrease Appendix C93 Energy L&R Energy L&R ––Annual Resource CapabilityAnnual Resource Capability 2007-2016 Annual Available Resource Capability (in aMW) 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Base Thermal Hydro Contracts Gas Dispatch Peakers Load w / CI Energy L&R Energy L&R ––First Quarter Resource CapabilityFirst Quarter Resource Capability 2007-2016 Available Resource Capability for Q1 (in aMW) 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Base Thermal Hydro Contracts Gas Dispatch Peakers Load w / CI Appendix C94 Energy L&R Energy L&R ––Second Quarter Resource CapabilitySecond Quarter Resource Capability 2007-2016 Available Resource Capability for Q2 (in aMW) 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Base Thermal Hydro Contracts Gas Dispatch Peakers Load w / CI Energy L&R Energy L&R ––Third Quarter Resource CapabilityThird Quarter Resource Capability 2007-2016 Available Resource Capability for Q3 (in aMW) 0 200 400 600 800 1,000 1,200 1,400 1,600 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Base Thermal Hydro Contracts Gas Dispatch Peakers Load w / CI Appendix C95 Energy L&R Energy L&R ––Fourth Quarter Resource CapabilityFourth Quarter Resource Capability 2007-2016 Available Resource Capability for Q4 (in aMW) 0 200 400 600 800 1,000 1,200 1,400 1,600 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Base Thermal Hydro Contracts Gas Dispatch Peakers Load w / CI LONG-TERM L&R TABULATION—CAPACITY (MW) CONFIDENTIAL Last Updated January 13, 2005 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 REQUIREMENTS Native Load (1,619) (1,666) (1,699) (1,745) (1,785) (1,841) (1,875) (1,926) (1,949) (2,007) (2,053) (2,091) Contracts Obligations (173) (169) (169) (169) (164) (164) (162) (162) (162) (162) (162) (162) Total Requirements (1,792) (1,835) (1,868) (1,914) (1,949) (2,005) (2,037) (2,087) (2,111) (2,169) (2,215) (2,253) RESOURCES Contracts Rights 312 326 329 329 330 329 211 212 211 212 212 212 Hydro Resources 1,156 1,098 1,090 1,090 1,056 1,049 1,018 996 988 980 979 978 Base Load Thermals 272 272 272 272 272 272 272 272 272 272 272 272 Gas Dispatch Units 179 303 303 308 303 303 307 303 307 308 308 303 Peaking Units 243 243 243 243 243 243 243 243 243 243 243 243 Total Resources 2,161 2,243 2,238 2,242 2,204 2,196 2,051 2,026 2,021 2,014 2,013 2,008 PEAK POSITION 369 408 370 328 255 191 14 (61) (90) (155) (202) (245) RESERVE PLANNING Planning Reserve Margin (252) (257) (260) (265) (269) (274) (278) (283) (285) (291) (295) (299) RESERVE PEAK POSITION 118 152 110 63 (13) (83) (263) (344) (375) (445) (497) (544) Capacity Loads & Resources Capacity Loads & Resources (MW)(MW) Appendix C96 2005-2016 Annual Available Resource Capability (in MW) 0 500 1,000 1,500 2,000 2,500 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Base Thermal Hydro Contracts Gas Dispatch Peakers Load w / Planning Reserve Capacity L&R Capacity L&R ––Annual Resource CapabilityAnnual Resource Capability IRP RequirementsIRP Requirements Energy: 33 aMW in 2010 308 aMW in 2015 590 aMW in 2025 Capacity: 83 MW in 2010 497 MW in 2015 860 MW in 2025 Appendix C97 Imputed Debt Discussion TAC Meeting January 25, 2005 •Buy versus build −Incremental cost of capital −Margin call costs −L/C costs •Credit ratings impact −Balance sheet – capital structure −Interest coverages −Debt ratio Costs of Financing for Acquiring New Resources 2 Appendix C98 BBBBBATOTAL DEBT/TOTAL CAPITAL BUSINESS PROFILE 706060551 685858522 7065655555503 6862625252454 6560605050425 6258584848406 6055554545387 5852524242358 5550504040329 52484835352510 3.05.05.08.08.011.010 2.84.04.07.07.010.09 2.53.53.55.55.57.58 2.23.23.24.54.56.57 2.03.03.04.24.25.26 1.82.82.83.83.84.55 1.52.52.53.53.54.24 1.01.51.52.52.53.53 1.02.02.03.02 1.01.51.52.51 BBBBBAINTEREST COVERAGE BUSINESS PROFILE S&P Financial Ratio Benchmarks Avista today Avista’s goal 3 Financing Costs of Purchased Power Contracts •S&P methodology (see attached articles) −Input portion of contracts as debt in our capital structure •Increases debt leverage •Increases interest expense and lowers coverage ratios •Assigns risk factor to each contract 4 Appendix C99 •Avista −Limited to date due to minimal level of contracts −Current contracts at very low costs −Future contracts may have bigger impact •Other Northwest utilities −Depends on level of PPA’s they have currently −Each company is different Current Situation 5 Appendix C100 1 Modeling Overview Modeling Overview and Processand Process 2005 Integrated Resource Plan Technical Advisory Committee Meeting February 17, 2005 James Gall 2 Topics of DiscussionTopics of Discussion AuroraXMP Overview IRP Timeline IRP Modeling Process Appendix C101 3 Aurora OverviewAurora Overview 4 What is AuroraWhat is AuroraXMPXMP?? Electric production cost model Avista’s use is to model the Western Interconnect, but could model any system Models operations on an hourly basis for up to 50 years Forecasts electric prices Determines when and what type of new resources to build Determines the value of a utilities portfolio of resources and contractual rights Appendix C102 5 What are Aurora InputsWhat are Aurora Inputs AuroraXMP LOADS FUEL PRICES AVISTA’S PORTFOLIO HYDRO CONDITIONS RESOURCE ATTRIBUTES TOPOLOGY 6 What are Aurora OutputsWhat are Aurora Outputs AuroraXMP COST OF EMISSIONS RESOURCE DISPATCH/COST MAJOR TRANSMISSON USAGE NEW RESOURCES/ RETIRED RESOURCES MARKET PRICES/ RESOURCE STACKS COST OF AVISTA’S PORTFOLIO Appendix C103 7 IRP TimelineIRP Timeline 8 TimelineTimeline February • Gather Assumptions • Set up Aurora database • Build Stochastic Models March-April • Complete Base Case • Complete Long- Term Studies • Complete Stochastic Analysis • Outline of Report Released May • Complete Scenarios/Futures• Evaluate Potential Avista Resources June • Draft document July- August • Draft of Report Released • Feedback • Final Draft Released Appendix C104 9 IRP Modeling ProcessIRP Modeling Process “Base Case Example”“Base Case Example” 10 Base Case ProcessBase Case Process Aurora LT Studies • Uses Aurora XMP • Market price forecast 2007-2026 • Identifies resources expansions given its cost assumptions Stochastic Model • Excel model that produces Monte Carlo data sets for Aurora • Used for hydro, natural gas prices, loads, and wind • Distributions will be discussed at the March TAC meeting Aurora Stochastic Runs • Uses Aurora LT resource build and Monte Carlo data sets derived from the stochastic model • Aurora runs each a Monte Carlo simulation hourly for 20 years with different hydro, NG, load and wind data points entered each iteration • Results in a distribution of market prices for each area and the cost to serve Avista’s load • For example the base case will take 33-41 days on one processor, on eight processors this should take 4-7 days to process for 200 iterations Appendix C105 11 Base Case Process (cont.)Base Case Process (cont.) Aurora Stochastic Runs • Uses Aurora LT resource build and Monte Carlo data sets derived from the stochastic model • Aurora runs each a Monte Carlo simulation hourly for 20 years with different hydro, NG, load and wind data points entered each iteration •Results in a distribution of market prices for each area and the cost to serve Avista’s load • For example the base case will take 33-41 days on one processor, on eight processors this should take 4-7 days to process for 200 iterations Prices & Costs Resource Optimization • Excel linear program • Optimizes Avista’s resource selection taking into account resource need • Takes into account capital requirements and timing of resource deficits • Evaluates costs on a NPV and risk basis • Evaluates scenarios Appendix C106 ModelingModeling Futures and ScenariosFutures and Scenarios 2005 Integrated Resource Plan Fourth Technical Advisory Committee Meeting February 17th 2005 Clint Kalich 2 Presentation Overview • IRP Definition Of A Future 3 • IRP Definition Of A Scenario 4 • Uses For Futures/Scenarios 5 • Some Basic Modeling Questions For Futures/Scenarios 6 • Proposed List of Scenarios 7 • Proposed List of Futures 8 • Additional Scenarios & Futures 9 Slide # Appendix C107 3 Definition Of A Future A FUTURE is modeled stochastically. In other words, Avista will model its options over 20 years with up to 200 Monte Carlo draws of varying hydro, load, gas, and wind conditions. Advantages: ability to quantitatively assess risk in addition to the expected base value Disadvantage: long solution times (i.e., 8 CPUs for up to a week), and results of a specific change can be more difficult to comprehend 4 A SCENARIO is not modeled stochastically. Instead we will use average forecasts of hydro, load, gas, and wind generation to simulate the impact of one assumption change. Advantages: quick solution time (i.e., 1 CPU for 4 hours), simpler to understand impact(s) of assumption change Disadvantage: unable to quantitatively assess risk of market volatility Definition Of A Scenario Appendix C108 5 Uses For Futures/Scenarios • Understand Potential Future Impacts And Their Magnitudes On: – Wholesale marketplace – Different resource options – Avista’s existing portfolio of load and resources – The Preferred Resource Strategy 6 Some Basic Modeling Questions For Futures And Scenarios • Will Future/Scenario Be Significantly Different Enough From Base Case To Warrant The Work? – We have to manage our time to meet Sept. 1 filing date • Will New Long-Term Runs Be Required? – Adds an extra day or more to work load • Is The Scenario AVA-Centric Or Must We Model Entire Northwest And/Or WECC? • Is Market Volatility Critical To What We Want To Measure (i.e., Do We Need Stochastic Output)? • Is Future/Scenario Reasonably Likely To Occur? • Can Future/Scenario Be Combined With Another? Appendix C109 7 Proposed List of Scenarios • High Gas * – Increase prices 50% to ~$9/dth • Low Gas * – Decrease prices 50% to approximately $3/dth • Emissions 2 * – $25/ton CO2 • Low Transmission * – Reduce NPCC estimate by approx. 2/3 to $500/kW • High Wind Penetration – 5,000 MW NW wind replaces other new resources • Boom/Bust – Change timing of new resources to “starve” and then “gorge” the marketplace • Loss of Large AVA Plant – Noxon “lost” for 5 years • High AVA Load – Double load growth to ~4% • Low AVA Load – No load growth • WECC-Wide Renewable Portfolio Standard – 25% renewables by end of study, replacing other new resources * Indicates new capacity expansion run will be required 8 Proposed List of Futures • Base Case – All Base Case assumptions included • Volatile Gas Prices – Double base case volatility (sigma) from 50% of mean to 100% of mean – Remaining Base Case assumptions unchanged • Emissions Case 1 – See Lyons presentation – Remaining Base Case assumptions unchanged Appendix C110 9 Additional Scenarios and Futures • TAC Recommendations/Changes to Proposed Scenarios/Futures Appendix C111 1 Modeling AssumptionsModeling Assumptions 2005 Integrated Resource Plan Technical Advisory Committee Meeting February 17, 2005 James Gall 2 Discussion ItemsDiscussion Items Time frame Inflation What we are modeling Fuel forecasts Gas revisited Coal Other New Resources Resources under construction Renewable Resources Portfolio (RPS) Hydro Wind Thermal resource commitment logic & variable O&M Thermal forced outage and maintenance Loads Appendix C112 3 Time FrameTime Frame Hourly 20 year study Study time frame is between 2007- 2026 Why begin in 2007? Report will not be completed until end of 2005 2006 is within short-term planning cycle Avista does not have a resource need until 2009/10 4 InflationInflation Inflation is used on Aurora’s cost inputs Based on Global Insights July 2004 Forecast Growth Rates: 2005- 2009: 1.6% 2010- 2014: 2.2% 2015- 2019: 2.7% 2020- 2027: 3.1% What is the value of $100 invested today if you earned the assumed inflation each year for the life of this study $100 $110 $120 $130 $140 $150 $160 $170 $180 $190 $200 2005 2010 2015 2020 2025 Appendix C113 5 North American Electric GridNorth American Electric Grid Picture Courtesy of NERC 6 Aurora TopologyAurora Topology Appendix C114 7 - 2.00 4.00 6.00 8.00 10.00 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 $/M M B t u Henry Hub Sumas Malin Forecasted Natural Gas PricesForecasted Natural Gas Prices Annual Average Prices (Nominal Dollars)Annual Average Prices (Nominal Dollars) Historic Forecast Key Assumptions • July 2004 Forward Price Curves for 2005 through 2007 • 2005- 07: -7.1% • Avg. Growth Rates – Based on July Global Insights forecast • 2007- 09: 1.9% • 2010- 20: 3.2% • 2020- 30: 3.8% New Escalation Rates New Escalation Rates Available in AprilAvailable in April Malin, Sumas, Rockies, AECO prices are directly input into Aurora Topock & Opal use EPIS basin differentials versus Henry Hub Local transportation charges are applied to the basis to reach each area in Aurora ~11 to 32 cents 8 Coal ForecastCoal Forecast Western Interconnect coal prices are based on Aurora database prices which are derived from FERC Form 423 and Electric Power Monthly $2005 per MMBtu – Arizona: $1.32 – Canada: $1.22 – California: $2.02 – Colorado: $1.01 – Montana: $0.65 – Nevada: $1.41 – New Mexico: $1.62 – Utah: $1.08 – Washington/Oregon: $1.22 – Wyoming: $0.88 Colstrip prices are mine mouth estimates and are lower then the estimate for Montana EIA’s Annual Energy Outlook 2005 was used to as growth rates for all coal prices (real escalation) Year Escalation 2005 0.50% 2006 0.20%2007 -0.90%2008 -0.20%2009 -0.80%2010 -1.20%2011 -0.60% 2012 -0.40% 2013 -0.30% 2014 0.00%2015 0.00%2016 -0.20%2017 0.20%2018 0.30%2019 0.30% 2020 0.30% 2021 0.70% 2022 0.70%2023 2.40%2024 0.70%2025 0.20%2025+ 0.10% Appendix C115 9 New Resources Under Construction TodayNew Resources Under Construction Today Resources added to the Aurora database New resources is based on the California Energy Commission list as of Dec 2004 We included plants that are either under construction or likely to be build 12,150 MW of capacity 9 10,000 MW of gas 9 1,300 MW are renewable 9 850 MW of coal 10 Renewable Portfolio Standards (RPS)Renewable Portfolio Standards (RPS) Currently RPS is law in 5 Western States 1. Arizona-by 2007 1.1% of energy is from renewables, 50% of which is solar 2. California-by 2017, 20% of energy is from renewables 3. Colorado-by 2015, 10% of energy is from renewables of which 4% is from solar 4. Nevada-by 2013, 15% of energy is from renewables, .75% from Solar 5. New Mexico-by 2011, 10% of energy is from renewables Northwest Conservation Council assumptions used for resource types and construction dates and amended for change in study period Appendix C116 11 RPS Resources Added per YearRPS Resources Added per Year Avg 2.2 MWAvg 4.6 MWAvg 14.3 MWNevada- South Avg 13.6 MW Pre 2010: 18.75 MW Post 2010: 69 MW Pre 2010: 2.25 MW Post 2010: 9 MW Geothermal Pre 2014: 25 MW + 200 MW 2011 + 250 MW 2014 Post 2015: 50 MW Avg 44 MW Pre 2012: 87 MW Post 2012: 115MW Pre 2012: 20.4 MW Post 2012: 3 MW Pre 2010: 90.75 MW Post 2010: 101.25 MW Pre 2010: 53.25 MW Post 2010: 59.25 MW Wind Avg 2.2 MWColorado Avg 6.7 MWNevada- North New Mexico Pre 2012: 38.7 MW Post 2012: 5.25 MW Arizona Pre 2010: 12.75 MW Post 2010: 28.5 MW California- South Pre 2010: 11.25 MW Post 2010: 27 MW California- North SolarBiofuelsArea * Total equals approximately 10.4 GW of Capacity by 2007 12 HydroHydro 60 year average hydro conditions based a recent head water study used for Aurora expansion studies For stochastic studies 1 of the 60 years will be used for each of the Monte Carlo iteration Energy is shaped to load using the Aurora hydro shaping logic All Pacific Northwest hydro operations are modeled as a single plant with a 44% capacity factor for the average water year Avista resources are modeled separately to track portfolio costs and use these average water year capacity factors Clark Fork: 39.3% Mid Columbia: 52.5% Spokane River: 69.3% Appendix C117 13 WindWind Concerns with previous studies that model wind Wind is constant for each month, no hourly variation Overstates the operational and financial value of these project Our plan to model wind Each area modeled has an hourly wind shape using a Monte Carlo distribution Wind shapes for the Northwest use historical wind speeds to develop mean capacity factors Wind shapes for outside the Northwest use mean capacity factors developed by SSG-WI (Seems Steering Group- Western Interconnect) We plan to model a high wind penetration scenario to determine impact on wholesale market place in the Northwest 14 Thermal Resource Commitment Logic and VOMThermal Resource Commitment Logic and VOM Startup Fuel Amounts and Costs CCCT:$25/MW per start & 3.6/mmBTU per MW SCCT Aero:$75/MW per start & 0/mmBTU per MW SCCT Frame:$25/MW per start 3.45/mmBTU per MW Steam: TBD Coal:Not Modeled Min/Up times CCCT:16 hours up & 8 hours down SCCT Aero:13 hours up & 6 hours down SCCT Frame:16 hours up & 8 hours down Steam:19 hours up & 10 hours down Coal:96 hours up & 24 hours down Variable O&M Based on Aurora database except for Avista’s generators Appendix C118 15 Thermal Resource Forced Outages and MaintenanceThermal Resource Forced Outages and Maintenance --Modeled as Modeled as deratesderates 5%5%Geothermal 5%5%Other Assumed in hourly distribution Assumed in hourly distribution Wind 10%Assumed in hourly distribution Solar 10-12% in shoulder months & 0-5% in others 10%Nuclear 17.6% in shoulder months10%Coal 10%10%Gas- Steam 10%10%SCCT- Frame 7.5%7.5%SCCT- Aero 5%5%CCCT Maintenance RateForced Outage RatePlant Type 16 Regional Load and GrowthRegional Load and Growth Area loads are based on the Aurora database (2003 levels displayed in blue) Annual load growth is based on WECC sub area forecasts between 2003 to 2013 (aMW displayed in red) Load growth estimates are applied to all years Total Western Interconnect loads grow at 2.25% each year Annual and monthly load shapes are consistent with the latest Aurora database 15,405 34,185 1,114 8,081 2,570 3,695 5,5752,812 1,863 1,185 2,195 7,709 6,926 Appendix C119 17 Western Interconnect and NW Loads by YearWestern Interconnect and NW Loads by Year - 20 40 60 80 100 120 140 160 180 aG W 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% % o f W e s t e r n I n t e r c o n n e c t WI 94 97 99 101 103 106 108 110 113 115 118 121 123 126 129 132 135 138 141 144 148 151 154 158 NW 16 16 17 17 17 18 18 18 19 19 19 20 20 20 21 21 21 22 22 23 23 23 24 24 NW as a % of WI 17% 17% 17% 17% 17% 17% 17% 17% 17% 16% 16% 16% 16% 16% 16% 16% 16% 16% 16% 16% 16% 16% 15% 15% 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 Appendix C120 1 Treatment of Treatment of EmissionsEmissions 2005 Integrated Resource Plan Fourth Technical Advisory Committee Meeting February 17, 2005 John Lyons 2 Presentation OverviewPresentation Overview Slide #’s • Issues in the Treatment of Emissions 3 • Environmental Issues 4 - 5 • Policy Issues 6 - 15 • Engineering Issues 16 • Economic Issues 17 - 19 • Planning Recommendations 20 - 21 Appendix C121 3 Issues in the Treatment of EmissionsIssues in the Treatment of Emissions There are four main issues to consider in resource planning concerning the treatment of emissions: 1. Environmental 2. Policy 3. Engineering 4. Economic 4 Environmental IssuesEnvironmental Issues •Environmental issues in regards to emissions are a result of greenhouse gases or carcinogenic substances as a result of the burning of fossil fuels. • Greenhouse gases include: carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride. • Greenhouse gases are often measured in global warming potentials (GWP) or converted into CO2 equivalents (CO2e) • Greenhouse gases are not currently being regulated on a federal level for utilities, but there have and are several attempts to do so • The US, EU, Canada, Russia, Japan, China and India collectively account for 75% of greenhouse gas emissions (Associated Press, 2005) Appendix C122 5 Magnitude of Environmental IssuesMagnitude of Environmental Issues Source: EIA 6 Emissions can best be described as an externality, so there is an inherent benefit for producers to allow emissions because markets will not take societal costs into account. There are three approaches to regulating an externality: 1. Direct command-and-control regulation: nearly impossible to get right. 2. Quantitative limits: give each entity a quantity and allow them to trade, which develops a market. 3. Price or tax mechanisms: set prices, fees or taxes. (Nordhause, 2001) Policy IssuesPolicy Issues Appendix C123 7 Western State Laws Concerning EmissionsWestern State Laws Concerning Emissions California • 2002 vehicle CO2 emissions bill effective 1/1/06. •Noxious oxide emissions limits on power plants to 5 parts per million Jan. 1, down from 8 ppm • Governor is expected to propose new restrictions for sulfur oxide, noxious oxide and mercury emissions this year. •CPUC is currently considering if utilities and energy generators can “add the cost of meeting any new state and/or federal CO2 emission regulations to existing contracts.”(Hamm, 2005) 8 Western State Laws Concerning EmissionsWestern State Laws Concerning Emissions Idaho • No active legislation regarding greenhouse gases Nevada • No active legislation regarding greenhouse gases Appendix C124 9 Western State Laws Concerning EmissionsWestern State Laws Concerning Emissions Oregon • 1997 – first state level CO2 standards in the nation • Requires utilities offset CO2 emissions exceeding 83% of state-of- the-art gas CCCT by paying into the Climate Trust of Oregon • Compliance with the CO2 standard through 4 methods 1. Efficiency improvements 2. Cogeneration 3. Offset projects – tree planting 4. Pay fee to offset project fund 10 Western State Laws Concerning EmissionsWestern State Laws Concerning Emissions Washington • 2004 – New fossil-fueled thermal electric generating facilities of greater than 25 MW will have a CO2 mitigation plan including one or more of the following: (a) Pay a third party to provide mitigation (b) Purchase carbon credits (c) Cogeneration Appendix C125 11 The Clean Air Act of 1990 • Capped sulfur dioxide emissions at 8.9 million tons per year starting in 2008 • Capped nitrogen oxide emissions at 2 million tons per year starting in 2008. • This will result in about 85% reduction in current allowances. (Silverstein, 2005) Federal Emissions RegulationsFederal Emissions Regulations 12 McCain – Lieberman (Climate Stewardship Act) S. 139 •Originally submitted in January 2003 and resubmitted in March 2004 • Goal - reduce heat trapping gas emissions in two phases through “a market-based system of tradable allowances” • Utility would posses a permit for each ton of heat-trapping gases emitted • Covers four groups who emit over 10,000 metric tons annually • Essentially covers 90% of all CO2 emissions in 2 phases Phase 1 2010 – 2015: reduce to 2000 levels Phase 2 2016 – 2020: reduce to 1990 levels Federal Emissions RegulationsFederal Emissions Regulations Appendix C126 13 Possible Effects of McCain – Lieberman •MIT study concluded that the bill would impact consumers $20 per year • Charles River Associates (CRA) study found a cost of $350 per year to 2010 and increasing to $530 per household by 2020. Also found that costs could be as high as $1,300 per year given different assumptions • CRA estimates increased price of electricity to be 7 – 9%, and the cost of coal to increase 51 – 140% (Glassman, 2003) Federal Emissions RegulationsFederal Emissions Regulations 14 Clear Skies Act of 2005 • Currently being debated as an amendment to the Clean Air Act of 1990 • Ignores carbon and sets limits on sulfur dioxide, nitrogenoxides and mercury • Reduce the 3 pollutants by 70% by 2018 • Companies operating below their cap can sell credits Federal Emissions RegulationsFederal Emissions Regulations Appendix C127 15 International Emissions RegulationsInternational Emissions Regulations Kyoto Protocol - 1997 • Goal is to reduce CO2 emissions by 20% below 1990 levels internationally • Accepted by 141 countries but restrictions only affect 35 industrial nations • Became effective on February 16, 2005 when Russia ratified it in November • Rejected by the US because of cost and lack of inclusion of emerging industrial economies like China and India • Covers six different greenhouse gases, mainly CO2 • The EU started an emissions trading system within the last few months to trade credits from the quotas assigned to 12,000 industrial facilities 16 Engineering IssuesEngineering Issues • The current state of emissions control technology is going to be in direct correlation with current and expected emissions regulations. • Coal fired facilities have the greatest cost risk for emissions because of the high carbon content • Higher initial costs but greater coal burning efficiencies • Movement from sub-critical to supercritical units in steam-electric pulverized coal within 20 years • Coal gasification – full commercialization as soon as 2011 • Coal gasification with sequestration – in development • Can significantly reduce the other 3 regulated pollutants (SOx, NOx, and HG) – i.e. new technologies promise 95% mercury capture Appendix C128 17 Economic Issues Economic Issues --Treatment of EmissionsTreatment of Emissions The planning issue of emissions regulation consists of three key ideas: 1. What is or will be regulated? • CO2 or CO2e? • Tighter Hg, SOx, and NOx standards? 2. When will it be regulated? • 2010 and 2016 for McCain-Lieberman? 3. What type of regulation will be enacted? • State, federal or combination? 18 Economic Issues Economic Issues --Other UtilitiesOther Utilities PacifiCorp •2004 IRP base case was developed using the McCain-Lieberman legislation proposal as a basis. •Used an inflation adjusted amount of $8/ton of CO2 in 2008 dollars. PGE •2002 IRP - no CO2 tax in the base case and a $40 per ton CO2 tax scenario Idaho Power • 2004 IRP has a base case of $12.80/ton of CO2 by 2008. Avista • 2003 IRP - Modeled a scenario with then-current NPCC assumption— prices rising to $11/ton in 2023 Appendix C129 19 Economic Issues Economic Issues --RecommendationsRecommendations The National Commission on Energy Policy – December 2004 • 2010 - Implement a mandatory tradable permit system with an initial cost of $7 per metric ton of CO2 equivalent • 2015 - Link to efforts by other developing and developed countries to reduce greenhouse gases 20 Planning Recommendations Planning Recommendations ––ScenariosScenarios •Base Case recognizes that there might be future regulation that will have an economic impact, but a cost is not being assigned at this time because of the uncertainty regarding the level and timing of the regulations. There presently is no law or regulation that requires CO2 mitigation. • Scenario 1: assume that a mandatory market-based tradable credit system for greenhouse gases with initial costs set at $7 per metric ton of CO2e and prices escalated into the future. (National Commission on Energy Policy, 2004) • Scenario 2: assume that a mandatory market-based tradable credit system for greenhouse gases with initial costs set at $40 per metric ton of CO2e and prices escalated into the future. Appendix C130 21 Planning Recommendations from TACPlanning Recommendations from TAC Do you believe that the range of prices assumed in the 3 cases adequately reflects potential CO2 obligations? • Base case with no assumed CO2e costs • Scenario 1 with $7 per metric ton costs • Scenario 2 with $40 per metric ton costs Other recommendations? Appendix C131 1 Supply Side OptionsSupply Side Options 2005 Integrated Resource Plan Technical Advisory Committee Meeting February 17, 2005 James Gall & John Lyons 2 Modeled Supply Side OptionsModeled Supply Side Options NG Combined Cycle (CCCT) NG Single Cycle (SCCT) Wind Turbine Coal (Pulverized, IGCC, IGCC with seq.) Solar Geothermal Biomass Alberta’s Tar Sands Nuclear Co-Gen DSM – Will be covered in March Appendix C132 3 NG Combined Cycle (CCCT) NG Combined Cycle (CCCT) 2005 dollars2005 dollars Type: Natural gas-fired combined cycle F class gas turbine Size (MW): 540 baseload and 610 peak Heat Rate (Btu/kWh): 7,030 Fuel source: Natural Gas First Available On-Line Date: 2007 Capital Cost $/KW: $632 Variable O&M: $3.02 Fixed O&M kW/Year:$9.00 Emissions (T/GWh): SO2 = .002 NOX = .039 CO2 = 411- 429 Location options: Any location Interconnection Costs: $16.80 kW/ year 4 NG Single Cycle (SCCT) NG Single Cycle (SCCT) 2005 dollars2005 dollars Type: Aero, such as the General Electric LM6000 Size (MW): 47 Heat Rate (Btu/kWh): 9,900 Fuel source: Pipeline natural gas First Available On-Line Date: 2007 Capital Cost $/KW: $672 Variable O&M: $8.96/MWh Fixed O&M kW/Year:$9.00 Emissions (T/GWh): SO2 = 0.09 NOX = 0.009-0.01 CO2 = 582 Location options: Any location Interconnection Costs: $0 kW/Year Appendix C133 5 NG Single Cycle (SCCT) NG Single Cycle (SCCT) 2005 dollars2005 dollars Type: Generic NWCC Industrial Machine Size (MW): 47 Heat Rate (Btu/kWh): 10,500 Fuel source: Pipeline natural gas First Available On-Line Date: 2007 Capital Cost $/KW: $420 Variable O&M: $4.48/MWh Fixed O&M kW/Year:$6.72 Emissions (T/GWh): SO2 = 0.09 NOX = 0.009-0.01 CO2 = 582 Location options: Any location Interconnection Costs: $0 kW/Year 6 Wind Turbine Wind Turbine 2005 dollars2005 dollars Type: Central station wind power project Size (MW): 100 Heat Rate (Btu/kWh): N/A Fuel source: Wind First Available On-Line Date: 2008 Capital Cost ($/KW): $1,131 Variable O&M ($/MWh): $1.12 (no PTC) + $4 shaping for first 1000 MW and $8 for remaining wind Fixed O&M kW/Year: $19.60 Emissions: N/A How many per study: 1,000 MW without new transmission Location options for NW Delivery: East of Cascades or Eastern Montana Interconnection Costs : $16.80 kW/Year Transmission cost from E. Montana to C. Washington: $1,781 kW (NPCC) $530/kW RMATS/Northwestern Appendix C134 7 Coal Coal --Pulverized Pulverized 2005 dollars2005 dollars Type: Pulverized coal-fired sub-critical steam-electric plant Size (MW): 400 Heat Rate (Btu/kWh): 9,550 Fuel source: Western low-sulfur subbituminous coal First Available On-Line Date: 2011 Capital Cost ($/KW): $1,392 Variable O&M ($/MWh): $1. 96 Fixed O&M kW/Year: $44.80 Emissions (T/GWh): SO2 = 0.575 NOX = 0.336 CO2 = 1012 Location options for NW delivery: Montana Interconnection Costs: Included in Capital Cost Transmission cost from E. Montana to C. Washington: $1,781 kW (NPCC) $530/kW RMATS/Northwestern 8 Coal Coal --IGCC IGCC 2005 dollars2005 dollars Type: Coal-fired integrated gasification combined-cycle with H- Class Turbine Size (MW): 474 gross and 425 net Heat Rate (Btu/kWh): 7,915 Fuel source: Western low-sulfur sub-bituminous coal First Available On-Line Date: 2011 Capital Cost ($/KW): $1,568 (Range is 1,456 – 1,792) Variable O&M ($/MWh): $1.68 Fixed O&M kW/Year: $50.51 Emissions (T/GWh): SO2 = Neg. NOX = < 0.11 CO2 = 791 Location options for NW delivery: Montana or Eastern Wash/Ore Interconnection Costs: Included in Capital Cost Transmission cost from E. Montana to C. Washington: $1,781 kW (NPCC) $530/kW RMATS/Northwestern Transmission cost 200 miles of 500kV: $352 kW Appendix C135 9 Coal Coal ––IGCC with Sequestration IGCC with Sequestration 2005 dollars2005 dollars Type: Coal-fired integrated gasification combined-cycle with 90% CO2 capture (Conceptual H-Class GT) Size (MW): 490 gross and 401 net Heat Rate (Btu/kWh): 9,290 Fuel source: Western low-sulfur sub-bituminous coal First Available On-Line Date: 2013 Capital Cost $/KW: $2,022 (Range $1,848 – $2,185) Variable O&M: $1.79 Fixed O&M kW/Year: $59.36 Emissions (T/GWh): SO2 = Neg. NOX = < 0.11 CO2 = 81 Location options for NW delivery : E. Montana Interconnection Costs: Included in Capital Cost Transmission cost from E. Montana to C. Washington: $1,781 kW (NPCC) $530/kW RMATS/Northwestern 10 Solar Solar 2005 dollars2005 dollars Type: Generic NPCC Unit Size (MW): 2 Heat Rate (Btu/kWh): 0 Fuel source: Sun First Available On-Line Date: 2007 Capital Cost ($/KW): $7,804 Variable O&M ($/MWh): N/A Fixed O&M kW/Year:$36.00 Emissions (T/GWh): N/A Location options for NW delivery : Desert Southwest (not viable for NW at this time) Interconnection Costs: $16.80 kW per year Appendix C136 11 Geothermal Geothermal 2005 dollars2005 dollars Type: Generic NWCC Unit Size (MW): 50 Heat Rate (Btu/kWh): 9,300 Fuel source: Geological Steam When available: 2007 Capital Cost ($/KW): $2,050 Variable O&M ($/MWh): Included in fixed O&M Fixed O&M kW/Year:$108 Emissions (T/GWh):N/A Location options for NW delivery : California, Nevada, Idaho Interconnection Costs: $16.80/ kW per year 12 Biomass Biomass 2005 dollars2005 dollars Type: Wood Residue, Landfill, Manure Size (MW): .5 - 25 Heat Rate (Btu/kWh): 11,100 – 14,500 Fuel source: Wood, Refuse, Manure When available: 2007 Capital Cost ($/KW): $1,523 – $3,472 Variable O&M ($/MWh): $0 – $10.38 Fixed O&M kW/Year: $75 - $140 Emissions (T/GWh): SO2 = N/A NOX = N/A CO2 = 720 – 1,116 Location options for NW delivery : Any Location Interconnection Costs: $16.80 kW per year Appendix C137 13 CoCo--Gen Gen 2005 dollars2005 dollars Type: Generic Unit Size (MW): 25 Heat Rate (Btu/kWh): 5,500 Fuel source: TBD First Available On-Line Date: 2007 Capital Cost ($/KW): $1,120 Variable O&M ($/MWh): $2.24 Fixed O&M kW/Year: $29 Emissions (T/GWh): TBD Location options for NW delivery : Any Location Interconnection Costs: $16.80 kW per year 14 Alberta’s Tar Sands Alberta’s Tar Sands 2005 dollars2005 dollars Type: Natural gas-fired 7F-class simple-cycle gas turbine plant with heat recovery steam generator Size (MW): 180 per unit Heat Rate (Btu/kWh): 5,800 (fuel charged to power) Fuel source: Pipeline natural gas First Available On-Line Date : 2011 Capital Cost $/KW: $566 Variable O&M ($/MWh): $3.11 Fixed O&M kW/Year: Included in Variable Costs Emissions (T/GWh): SO2 = Not Avail NOX = Not Avail CO2 = 365 How many per study: (3,000 MW total NW) Location options for NW delivery : Alberta Interconnection Costs: $10.43 kW per year Transmission cost from Fort McMurray to Celilio: $1,166/ kW (1,089 miles of DC at $2 million per mile and $1.32 billion for inverter stations) Appendix C138 15 Nuclear Nuclear 2005 dollars2005 dollars Type: Advanced Nuclear Power Plant Size (MW): 1,100 Heat Rate (Btu/kWh): 9,600 Fuel source: Natural Uranium First Available On-Line Date: 2020 Capital Cost ($/KW): $1,624 Variable O&M ($/MWh): $1.12 Fixed O&M kW/Year: $44.80 Emissions (T/GWh): N/A Location options for NW delivery : Anywhere Interconnection Costs: $16.80 kW per year 16 Regional Coal Resource OptionsRegional Coal Resource Options New Coal units are assumed to be an option for all areas in the Western Interconnect, although the costs to build new transmission is part of the capital requirement to build a new coal plant. Cost to build transmission is based on the Rocky Mountain Area Transmission Study (RMATS) S. California from Utah: $130/kW (500 MW max) S. California from Wyoming: $2,510/kW N. California from Wyoming: $2,675/kW Utah from Wyoming: $265/kW S. Nevada from Wyoming: $1,635/kW S. Idaho from Jim Bridger, Wyoming: $412/kW Transmission cost to serve local loads in states has a cost of $.5- $1.8 million per mile depending on voltage and location Appendix C139 17 Regional Tar Sands Transmission OptionsRegional Tar Sands Transmission Options Based on BPA and PG&E Estimates provided at recent NTAC meeting The study included 3,000 MW of capacity from Northern Alberta on one 500kV DC line, and does not include any AC support Study assumed $2,000,000 per mile to build transmission and requires 4 inverter stations at $440 million each and $30 million of communication equipment Inverter stations locations are: Fort McMurray (NE Alberta) Bell (Spokane area) Celilo (East of The Dalles, OR) Tesla (SE of San Francisco) 1,729 miles $5.248 billion to build ($1,749 /kW) 18 New Resource SummaryNew Resource Summary N/AN/AN/A$16.80 kW/yearCA/NV108.00Included in FC2,05020079,30050Geological SteamGeo-thermal- not NW N/AN/AN/A$530 - $1,781/kW CapitalMT19.606.12 - 9.121,1312011N/A100WindWind $16.80 kW/year 1,166/ kW Capital $16.80 kW/year $16.80 kW/year $16.80 kW/year $16.80 kW/year $530 - $1,781/kW Capital $352/kW Capital $530 - $1,781/kW Capital $530 - $1,781/kW Capital $0/kW/year $16.80 kW/year $16.80 kW/year Transmission Costs OR/WA AB OR/WA OR/WA DSW OR/WA MT OR/WA MT MT OR/WA OR/WA OR/WA Location 29.00 Included in VC 44.80 75 – 140 36.00 19.60 59.36 50.51 50.51 44.80 6.72 9.00 9.00 Fixed O&M $/kW N/AN/AN/A1.121,62420209,6001,100UraniumNuclear 720 –1,116N/AN/A0 – 10.38 1,523 –3,472200711,000-14,500.5 – 25Refuse/OtherBiomass 81<.11Neg.1.792,02220139,290401CoalCoal- IGCC w/ Seq. 791<.11Neg.1.681,56820117,915474CoalCoal- IGCC- Eastern WA/OR 791<.11Neg.1.681,56820117,915474CoalCoal- IGCC- Montana 1,012.336.5751.961,39220119,550400CoalCoal- Pulverized TBDTBDTBD2.241,12020075,50025TBACo-Gen 365N/AN/A3.1156620115,800180Oil Sands/ Co-GenTar Sands N/AN/AN/A07,8042007N/A2SunSolar-not NW N/AN/AN/A 6.12 - 9.121,1312008N/A100WindWind 582.009-.01.094.48420200710,50047GasSCCT- Industrial 582.009- .01.098.9667220079,90047GasSCCT- Aero 411- 429.039.0023.0263220077,030610GasCCCT CO2Tons/GWh NOXTons/GWh SO2Tons/GWh Variable O&M $/MWh Capital Cost $/kW Year Available Heat Rate Size (MW) Fuel SourceResource Type Appendix C140 1 DSM Integration BriefDSM Integration Brief 2005 Integrated Resource Plan Fifth Technical Advisory Committee Meeting March 23, 2005 Jon Powell 2 The “Evolution” of DSM Integration into the Avista IRP • General Avista DSM environment • Three general period – Up to 2000 – The 2003 IRP – The 2005 IRP Appendix C141 3 Overall Objective • Achieve a maximum level of cost-effective DSM acquisition • Equitably treat DSM in the development of that least-cost portfolio • Provide feedback for DSM operations regarding target markets, technologies etc 4 Unique DSM Characteristics • Annual resource acquisition is small relative to overall system or major supply-side acquisitions • Cumulative effect is much more significant – Avista acquisition 1978 to 2004 approximately 111 aMw (without degradation) • Historically Avista DSM has been a non- dispatchable resource • Until 2003 Avista DSM was tested against a single annual avoided cost – Negating any consideration of TOU targeting, load- shifting etc. Appendix C142 5 Significant Issues in Integrating DSM into the IRP • Avista desires to have obtain information useful to DSM operations from the IRP process – Actionable results – Meaningful insights – Relevant analytical feedback 6 Significant Issues in Integrating DSM into the IRP • Quality load research relevant to our service territory and customer base is difficult to obtain – Historically the NW has not had the need for the same quality of LR as California and similar areas – ELCAP, NPCC and our own M&E were hybridized to create usable load research for 2003 and 2005 – Improving the quality of our load research is costly Appendix C143 7 Significant Issues in Integrating DSM into the IRP • Avista DSM is generally an “all-comers” DSM tariff (per Schedule 90 and 190) –All non-residential energy-efficiency measures qualify for our programs – Residential programs are prescriptive only • An IRP that accepts or rejects specific non-residential measures is unrealistic from a regulatory obligation and operational standpoint • The results of the IRP does provide us with feedback that is valuable in targeting measures and long-term planning of DSM strategy 8 Our 2000 (and prior) Integration Methodology • Integration by price signal – Supply-side resource options are stacked / demand forecasts are calculated Æ an annual avoided cost – DSM options were evaluated and cost-effective resources were acquired • Cost-effective relative to the avoided cost price signal Appendix C144 9 Results • Analytical results were easily incorporated into DSM operations and provided for a consistent metric for operational decisions • No interaction between demand-side and supply- side resource options – DSM resources were small annual acquisitions – DSM was non-dispatchable • The annual avoided cost precluded targeting of on-peak loads, load-shifting options etc. – Relatively little TOU differential during this time period 10 Changing Resource Environment • Increasing complexity of market prices – Resulting in an increased need for a “richer” avoided cost price signal to meaningfully integrate DSM into the resource plan • Potential for increasing cost-effectiveness of dispatchable DSM options • Potential for improved economics of demand-response measures • Controlled Voltage Regulation (CVR) Appendix C145 11 2003 DSM Integration Methodology • Define meaningful “bundles” of DSM – Residential / non-residential – Lighting, HVAC etc – “dogs and cats” category of undifferentiated measures – Indexed to historical acquisition levels – Estimates of alternative acquisition at two incremental / two decremental incentive levels • Develop 8760 hour x 20 year load profile • Explicitly incorporate into AURORA as a resource • “Stack” results to develop a DSM supply curve 12 What we learned from the 2003 IRP • Two major issues – DSM supply curve was UCT based • Premised on differential incentive levels • Consistent with the utility cost nature of the IRP • A different perspective than “acquire all TRC cost-effective resource” approach – Operationally TRC cost-effective DSM resources were targeted and acquired – Supply curve was steep • Two potential causes – Time horizon of our estimates of market reaction to incremental /decremental incentives – Impact of regulatory restrictions on discriminatory pricing upon the supply curve • Explicitly integrating DSM into AURORA isn’t easy Appendix C146 13 Our 2005 Methodology • Utilizes price signal integration for energy DSM programs – Any future demand-response options would most likely be explicitly integrated into AURORA • Applies a “richer” 8760 hour x 20 year avoided cost price signal – Improved ability to distinguish and appropriately value different load shapes – Ability to determine value of load shifting strategies – Enhanced information for targeting of DSM operations – Is demanding of our load-research capabilities 14 Our 2005 Methodology • Utilizes a TRC pricing methodology • Subdivides DSM into more coherent and actionable components • Incorporates indexing to a realistic baseline to ensure realistic results • Is consistent with the NPCC DSM supply curve work Appendix C147 15 Integration of DSM into the 2005 Electric IRP Engineering team Power Optimization Analyst team Program design team Engineering / program design team Overall DSM team Develop 8760 hour loadshapes by NPCC+ categories Estimate non-energy benefits by NPCC+ category Calculate the TRC value of each NPCC+ category Calculate the TRC acquisition cost of each NPCC+ category Calculate the TRC B/C ratio of each NPCC+ category Stack the NPCC+ categories to create a DSM TRC supply curve Review the TRC supply curve, refine program, reiterate as necessary Determine target markets and economic potential by NPCC+ categoryDetermine non- incentive utility acquisition cost by NPCC+ category Engineering Analytical calc Program design Develop 8760 x 20 year forecast of Avista avoided costs Determine customer cost by NPCC+ category 16 Anticipated Results • Need to be caution in translating IRP results (or extrapolations from NPCC Power Plan) into DSM operations – Actual results of field operations are a superior indication of program viability • Reasonable likelihood that IRP will result in a 10% to 25% increase in DSM goal – Up from 4.6 aMW (40 million annual kWh’s) Appendix C148 17 DSM Business Plan Status • In a transition from a 2002-2005 DSM business plan based upon – Targeting no-cost / low-cost and lost opportunity measures – Tight cost controls – Pursuing ordered priorities of • Meet all regulatory and legal obligations • Field a cost-effective DSM portfolio • Return the tariff rider balance to zero in a timely manner 18 Actual and Projected Rider Balances $(14,000,000) $(12,000,000) $(10,000,000) $(8,000,000) $(6,000,000) $(4,000,000) $(2,000,000) $- $2,000,000 $4,000,000 January March May July September November January March May July September November January March May July September November January March May July September November January (BOM) WA Electric WA E projected ID Electric ID E pro jected WA Gas WA G projected ID Gas ID G pro jected Total Total pro jected Appendix C149 19 2006 DSM Business Plan • Be good stewards of ratepayer DSM funds – Pursue all available TRC cost-effective DSM resources • Maximize that cost-effectiveness by maintaining appropriate cost-control practices – Establish and maintain a regulatory mechanism that provides an adequate level of funding in the long-term – Nurture utility and non-utility infrastructure sufficient to acquire cost-effective DSM resources in the long-term 20 Recent Actions • Initiated a ramp-up of Idaho electric DSM in late 2002 – As the balance of that tariff rider approached zero – Several pilot programs in field or under consideration • Prescriptive rooftop HVAC program • Small commercial lighting marketing • Prescriptive Industrial compressed air • Prescriptive refrigeration • Grocery store re-commissioning • Residential CFL’s • Recent approval of an increase in Idaho electric incentives (effective March 15th) Appendix C150 21 In-Progress • Evaluating the timing of revisions to our Washington DSM tariff – To mirror our revisions in Idaho tariff – Expand successful pilot programs to Washington – Continue to evaluate additional pilot programs 22 DSM Actions Beyond the IRP • Development of a demand-side drought contingency plan – Development of programs to mitigate the adverse impact to our ratepayers • Approach – Develop appropriate programs • Rapid launch • Rapid impact – Perform necessary degree of program planning to prepare for rapid launch – Identify trigger conditions for launch and withdrawal of programs – Continual evaluation of conditions through the summer • Realistically … relatively little mitigation opportunity Appendix C151 23 Questions Appendix C152 Stochastic ModelingStochastic Modeling 2005 Integrated Resource Plan Fifth Technical Advisory Committee Meeting March 23rd 2005 Clint Kalich 2 Presentation OverviewPresentation Overview • Why Model Risk?3 • Risk Modeled In AURORA 4 • Limits of AURORA Risk Module 5 • Risk Modeling For 2005 IRP 6 • Hydro Variability 7-12 • Natural Gas Variability 13-18 • Load Variability 19-22 • Wind Variability 23-27 Slide # Appendix C153 3 Why Model Risk?Why Model Risk? • Learn Of Potential Variation Associated With Each Future • Measure Value Of Resources With Greater Degrees Of Optionality • Quantify Relationship Between Least Cost And Least Risk • Ensures Best Computer Hardware!!! 4 Risk Modeled In AURORARisk Modeled In AURORA • Modeling of Hydro, Fuel Prices, Forced Outage and Load • Values Can Vary By Load Area • Modeled Annually, Monthly, Daily and Hourly • Correlations Between Variables Allowed – XMP allows for negative correlations • Monte Carlo Iterations, & Latin Hypercube Appendix C154 5 Limits of AURORA Risk ModuleLimits of AURORA Risk Module •Cannot Model Custom Timeframes – e.g., weekly hydro with daily load •Solution: Develop Risk Modules (i.e., Big Spreadsheets) Outside of AURORA – 300 Iterations were developed – Upload iterations into AURORA database – Run each iteration through AURORA 6 Risk Modeling for 2005 IRPRisk Modeling for 2005 IRP • Key Variables Considered – Load, hydro, natural gas prices, wind • Entirely Outside Aurora – Through separate database tables linked into program • IRP runs will use between 200-300 iterations – Output stored in SQL or Oracle database Appendix C155 7 Hydro VariabilityHydro Variability • Hydro Data – Streamflows Are Normally Distributed – Generation Is Not Normally Distributed – NWPP 60-yr study encompasses ~75% of WECC hydro • OR, WA, Idaho, BC, MT • OWI (OR, WA, No. Id.) ~50% of WECC hydro • Random Draws Of Historical Years From Study – i.e., where calendar year 1965 is randomly drawn, hydro conditions from 1965 are used for all NW projects • Other WECC Hydro Constant @ EPIS Values 8 Hydro Distribution - OWI Annual Average 0 100 200 300 400 500 600 700 800 900 1,000 8. 5 9. 5 10 . 5 11 . 5 12 . 5 13 . 5 14 . 5 15 . 5 16 . 5 17 . 5 18 . 5 19 . 5 20 . 5 21 . 5 22 . 5 average gigawatts fr e q u e n c y Average = 13.7 aGW1,191 obs. Appendix C156 9 Hydro Distribution - OWI First Quarter 0 100 200 300 400 500 600 700 800 900 1,000 8. 5 9. 5 10 . 5 11 . 5 12 . 5 13 . 5 14 . 5 15 . 5 16 . 5 17 . 5 18 . 5 19 . 5 20 . 5 21 . 5 22 . 5 average gigawatts fr e q u e n c y Average = 15.4 aGW 10 Hydro Distribution - OWI Second Quarter 0 100 200 300 400 500 600 700 800 900 1,000 8. 5 9. 5 10 . 5 11 . 5 12 . 5 13 . 5 14 . 5 15 . 5 16 . 5 17 . 5 18 . 5 19 . 5 20 . 5 21 . 5 22 . 5 average gigawatts fr e q u e n c y Average = 16.8 aGW Appendix C157 11 Hydro Distribution - OWI Third Quarter 0 100 200 300 400 500 600 700 800 900 1,000 8. 5 9. 5 10 . 5 11 . 5 12 . 5 13 . 5 14 . 5 15 . 5 16 . 5 17 . 5 18 . 5 19 . 5 20 . 5 21 . 5 22 . 5 average gigawatts fr e q u e n c y 1,786 obs. Average = 10.8 aGW 12 Hydro Distribution - OWI Fourth Quarter 0 100 200 300 400 500 600 700 800 900 1,000 8. 5 9. 5 10 . 5 11 . 5 12 . 5 13 . 5 14 . 5 15 . 5 16 . 5 17 . 5 18 . 5 19 . 5 20 . 5 21 . 5 22 . 5 average gigawatts fr e q u e n c y 3,690 obs. Average = 11.8 aGW Appendix C158 13 Natural Gas VariabilityNatural Gas Variability • St. Dev. Of Prices Set At 50% Of Mean – Approximately $2.50/dth on $5.00/dth gas (2007$) – 81.4% serial correlation month to month • Based on 1995-2004 average @ Malin • Assumed Lognormal Price Distribution – Historical data does not appear lognormal – Standard industry assumption is lognormal 14 Natural Gas Price Distribution Annual Average 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 Natural Gas Price (2003$/dth) # o f o b s e r v a t i o n s Appendix C159 15 Natural Gas Price Distribution January 0 200 400 600 800 1,000 1,200 1,400 1,600 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 Natural Gas Price (2003$/dth) # o f o b s e r v a t i o n s Average Price = $5.360 16 Natural Gas Price Distribution April 0 200 400 600 800 1,000 1,200 1,400 1,600 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 Natural Gas Price (2003$/dth) # o f o b s e r v a t i o n s Average Price = $5.269 Appendix C160 17 Natural Gas Price Distribution July 0 200 400 600 800 1,000 1,200 1,400 1,600 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 Natural Gas Price (2003$/dth) # o f o b s e r v a t i o n s Average Price = $5.121 18 Natural Gas Price Distribution October 0 200 400 600 800 1,000 1,200 1,400 1,600 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 Natural Gas Price (2003$/dth) # o f o b s e r v a t i o n s Average Price = $5.165 Appendix C161 19 Load VariabilityLoad Variability • Avista Wants to Accurately Model WECC • Analyzed 1998-1999 Hourly Loads from EIA to Generate Statistics (3 million data points!) – Same as 2003 IRP – ignored volatile 2000-01 period • Modeled Variation Both Weekly and Daily – Avista is assumed presently to have OWI statistics 20 Load Variability, ContinuedLoad Variability, Continued • Each WECC Area Analyzed Separately – 14 Areas, plus Avista – Calculated means and standard deviations • monthly variation in OWI varies between 2.2% and & 4.0% – Correlated each area to OWI • Ensured relationships were statistically significant • looked at each weekday separately to eliminate weekly trends • averaged weekday results to obtain final values Appendix C162 21 Load Variability, ContinuedLoad Variability, Continued January February March April May June July August September October November December Alberta 0.659 Not Sig 0.481 Not Sig Mix 0.635 0.668 Mix Mix 0.479 Not Sig Not Sig Arizona 0.440 0.664 Not Sig Mix (0.289) 0.666 Not Sig Not Sig Not Sig Not Sig Mix Not Sig British Col 0.918 0.838 0.825 0.733 0.617 Not Sig 0.560 Not Sig 0.638 0.809 0.525 0.890 CA North Not Sig 0.734 Not Sig Not Sig Not Sig 0.771 Mix 0.757 0.789 Not Sig Mix Not Sig CA South Not Sig Mix Not Sig Not Sig Mix 0.680 Mix 0.500 0.778 Not Sig Not Sig Not Sig Colorado 0.623 Not Sig 0.567 Mix Mix Not Sig Not Sig Not Sig Not Sig 0.655 0.629 0.571 ID South 0.673 0.747 0.882 Not Sig Not Sig 0.758 Mix 0.789 0.733 0.561 0.587 0.813 Montana 0.894 0.773 0.755 0.651 0.405 0.599 0.786 0.648 0.752 Not Sig 0.856 0.898 NV North Mix Not Sig Not Sig Not Sig Not Sig Not Sig Not Sig Not Sig Not Sig Mix 0.476 Not Sig NV South Not Sig 0.641 0.513 Mix Not Sig 0.729 Mix Not Sig Mix Not Sig 0.461 Mix New Mexico 0.384 Mix Mix Not Sig Not Sig Mix Not Sig Mix Not Sig Not Sig Mix Mix Utah 0.816 Not Sig 0.669 0.697 0.610 0.698 0.703 0.604 0.611 Not Sig 0.561 0.837 Wyoming 0.765 Mix 0.641 Not Sig Mix Mix Not Sig Not Sig 0.483 Not Sig 0.522 0.633 * "Not Sig" implies that relationship was not statistically significant, "Mix" explains that the relationship was not a consistent across time Load Correlation Values to OWI (Average of Weekdays) 22 OWI Load Variation - 20 Iterations January 2007 17 18 19 20 21 22 23 24 25 26 Da y 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 day of month av e r a g e g i g a w a t t s Min 80% CI Lo Mean 80% CI Hi Max Appendix C163 23 Wind VariabilityWind Variability • Previous Attempts At Modeling Wind Have Simplified Wind Problem – Assume monthly average generation is constant every hour – Simple mean & standard deviatation without correlation • Obtaining Good Wind Data is Difficult • Avista Is Using OSU/BPA Database Of Hourly Wind Data As Source For 2005 IRP 24 Stateline Data 1000 Continuous Hours - 20 40 60 80 100 120 140 160 180 200 1 30 59 88 11 7 14 6 17 5 20 4 23 3 26 2 29 1 32 0 34 9 37 8 40 7 43 6 46 5 49 4 52 3 55 2 58 1 61 0 63 9 66 8 69 7 72 6 75 5 78 4 81 3 84 2 87 1 90 0 92 9 95 8 98 7 av e r a g e m e g a w a t t s Statistics Mean 49.7 aMW StDev% 130% N-1Corr 95% Appendix C164 25 Simple Mean/StDev 1000 Continuous Hours - 20 40 60 80 100 120 140 160 180 200 1 30 59 88 11 7 14 6 17 5 20 4 23 3 26 2 29 1 32 0 34 9 37 8 40 7 43 6 46 5 49 4 52 3 55 2 58 1 61 0 63 9 66 8 69 7 72 6 75 5 78 4 81 3 84 2 87 1 90 0 92 9 95 8 98 7 av e r a g e m e g a w a t t s Statistics Mean 70.9 aMW StDev% 78% N-1Corr 1% 26 OSU Kennewick, WA 1000 Continuous Hours - 20 40 60 80 100 120 140 160 180 200 1 30 59 88 11 7 14 6 17 5 20 4 23 3 26 2 29 1 32 0 34 9 37 8 40 7 43 6 46 5 49 4 52 3 55 2 58 1 61 0 63 9 66 8 69 7 72 6 75 5 78 4 81 3 84 2 87 1 90 0 92 9 95 8 98 7 av e r a g e m e g a w a t t s Statistics Mean 89.9 aMW StDev% 91% N-1Corr 92% Appendix C165 27 5-Site NW Average (OSU Database) 1000 Continuous Hours - 20 40 60 80 100 120 140 160 180 200 1 30 59 88 11 7 14 6 17 5 20 4 23 3 26 2 29 1 32 0 34 9 37 8 40 7 43 6 46 5 49 4 52 3 55 2 58 1 61 0 63 9 66 8 69 7 72 6 75 5 78 4 81 3 84 2 87 1 90 0 92 9 95 8 98 7 av e r a g e m e g a w a t t s Statistics Mean 113.6 aMW StDev% 54% N-1Corr 96% Appendix C166 Avista’s 230 kV Upgrade Project March 23, 2005 Technical Advisory Committee by Randy Cloward The West of Hatwai Transmission Path • Flowgate separating Eastern Washington and the load centers of the I-5 corridor • Consisting of BPA and Avista 115-500 kV Transmission Lines • 2002 Rating – 2800 MW • 2002 Peak Demand – 3500-4000 MW Cabinet Gorge Bell (BPA) Noxon Benewah Pinecreek Rathdrum Shawnee Moscow 230 Hatwai (BPA) Lolo Dry Creek Beacon Boulder BPA AVA BPA AVA 115 kV 230 kV 500 kV Appendix C167 2001 - West of Hatwai Emerges as a Transmission Constraint •During the Energy Crisis of 2001, Aluminum smelter loads are shutdown in Spokane and Western Montana •The combined load loss and new generation adds nearly 1000 MW of flow on the West of Hatwai Transfer path •Avista and BPA collaborate on a regional solution. •BPA announces plans to construct a 500 kV transmission line between Bell (Spokane) and Grand Coulee •Avista announces plans to reinforce its 230 kV delivery system before the end of 2006 Avista 230 kV Upgrade Project 2000 MVA Beacon- Rathdrum Line Energized April 2004 - $19M 1000 MVA Benewah- Shawnee Line Phase 1 (south) Nov 2006 - $29M Phase 2 (north) Nov 2007 - $15M 500 MVA Boulder Substation and Transmission Lines June-December 2005 - $16M 250 MVA Dry Creek Sub Energized December 2004 - $12M Total Investment 2003-2006 $106M Fiber Optic “Ring” System Per WECC Standard Nov 2006 - $7MShawnee Noxon Benewah Pinecreek Rathdrum Moscow 230 Hatwai (BPA) Lolo Dry Creek Boulder Appendix C168 Beacon-Rathdrum Facts Rathdrum 230 kV Substation Reconstruction ($3M) Becomes Avista’s 1st Fully Redundant Substation Capacity Increase from 300 to 2000 MVA ($16M) Avista’s highest capacity transmission facility “Mechanically” strongest transmission line ever constructed by Avista Utilities 25.2 miles, 188 towers, 714 tons of conductor 2600 tons of steel, 12 months to construct Appendix C169 Boulder Facts Boulder 500 MVA Substation - New Construction ($8M) 1st Energization June 2005. December Completion Three 230 kV and Six 115 kV Transmission Lines 500 yards of concrete, 10,000 control wire connections Additional transformation to the Spokane Valley Liberty Lake – 2nd fastest growing city in the State of Washington 230 and 115 kV Transmission Integration ($8M) 135 steel towers, 285,000 feet of conductor, 8 months of contract labor construction Appendix C170 Dry Creek Facts Dry Creek 250 MVA Substation - New Construction ($8M) Capacitor Bank installation – 200 MVAR Forms 35-mile “ring” of 230 kV lines around the Lewiston-Clarkston Valley 135 Avista employees, 100 tons of steel, 1000 cubic yards of concrete, 10,000 control wire connections 230 kV Line Capacities Increase from 400 to 800 MVA ($2M) Conversion of Lolo to Fully Redundant Substation ($2M) Appendix C171 Benewah-Shawnee Facts Benewah 250 MVA Substation - Reconstruction ($8M) Add 200 MVAR Capacitor Bank 1000 MVA Benewah-Shawnee Transmission Line ($36M) 60-Miles, 360 steel towers, 4000 tons of steel, 75% Reconstruction, 25% New Construction Significant Challenges Steel Escalation June 03 ($300/ton) – April 04 ($600/ton) Chinese increase consumption from 100 to 300 M tons Avista Response to Steel Escalation Value Engineering Reduces Estimated Cost by $4M Alliance Agreement with Steel Pole Supplier enables dollar cost averaging of steel over project life (2005-07) Appendix C172 Communication Plan Avista Constructing Two Fiber Optic Loops L/C Valley, 35 Miles ($1M) North of Benewah, 100 Miles of Fiber plus Microwave ($4M) Benewah-Shawnee Fiber and Substation Comm. ($2M) “Redundant communication pathways required for the operation of stability limited 230 kV transmission lines” (WECC) Appendix C173 Summary Reinforcement from Spokane, WA to Coeur d’ Alene, ID Beacon-Rathdrum (increase east-west capacity) Boulder Substation (load demand in Spokane Valley) Reinforcement in Lewiston-Clarkston Valley Dry Creek Substation (“ring” of 230 kV lines) Hatwai transmission lines (increase capacity) 230 kV Connection through the Palouse Benewah-Shawnee (backup supply to Shawnee Substation – mitigates overloads on parallel path lines) Fiber Optic Communication (automatic control of 230 kV lines and Clark Fork hydro generation) Appendix C174 1 PreliminaryPreliminary LongLong--term Electric Forecast & term Electric Forecast & Capacity Expansion ResultsCapacity Expansion Results 2005 Integrated Resource Plan Technical Advisory Committee Meeting March 23, 2005 James Gall 2 Discussion ItemsDiscussion Items 1) Resource Assumptions A. Generation Assumptions B. Discount Rates C. Transmission Assumptions D. Resource Restrictions 2) Electric Market Forecasts A. Mid Columbia Prices B. Marginal Heat Rate for the Northwest C. Hourly Price Curve D. Other Hub’s Electric Price Forecasts 3) Capacity Expansion Results A. What is a Capacity Expansion B. Northwest L&R C. Northwest New Resources D. Western Interconnect New Resources Appendix C175 3 Resource AssumptionsResource Assumptions 4 New Resource SummaryNew Resource Summary Yellow Indicates Change From Last TAC MeetingYellow Indicates Change From Last TAC Meeting 178.00Inc. in FC2,05020079,30050Geological SteamGeothermal 38.006.12 - 9.121,1312011N/A100WindWind 29.00 Inc. in VC 75.00 125 – 250 36.00 76.00 67.00 62.00 11.25 15.00 19.00 Fixed O&M $/kW 1.121,62420209,6001,100UraniumNuclear 0 – 10.38 1,523 – 3,472 200711,000- 14,500 1 – 25Refuse/OtherBiomass 1.792,02220139,290401CoalCoal- IGCC w/ Seq. 1.681,56820117,915425CoalCoal- IGCC 1.961,39220109,550400CoalCoal- Pulverized 2.241,12020075,50025TBACo-Gen 3.1156620115,800180Oil Sands/ Co-GenTar Sands 07,8042007N/A2SunSolar 4.48420200710,50047GasSCCT- Industrial 8.9667220079,90047GasSCCT- Aero 3.0258820077,030610GasCCCT Variable O&M $/MWh Capital Cost $/kW Year Available Heat Rate Size (MW) Fuel SourceResource Type Appendix C176 5 Discount Rates Used for Capacity ExpansionDiscount Rates Used for Capacity Expansion 9.6% 7.8% 9.2% 8.9% 9.2% Weighted Discount Rates 10.68%9.15%4.9%Discount Rate Percent Ownership IPPIOUPUD 70%15%15%Renewables 20%40%40%SCCT 60%20%20%CCCT 50%25%25%Coal/Tar Sands Discount rates are required to calculate the fixed costs associated with each new resource (Model requires $/MW/Week for each resource) and to calculate the present value of each resource) Discount Rates are based on NPCC 5th Power Plan 6 Transmission CostsTransmission Costs AURORAXMP does not have transmission expansion logic, nor does it account for transmission within a region To overcome simplistic topology within the model, transmission cost adders are included for resources that normally require new transmission to be built (Modeled in Capacity Expansion studies) If the model selects a plant outside its region, it is moved to that area for hourly price forecast studies Wind 230 500 100 0.90 35 125 250 8.90 $4Wind OWI MT 500 1,500 900 2.00 40 1,840 1,227 8.90 $13Coal 500 1,500 250 2.00 40 540 360 8.90 $5 Coal OWI MT 500 1,500 900 2.00 40 1,840 1,227 8.90 $13 Coal IDSo WY 500 1,500 500 2.00 40 1,040 693 8.90 $8 Coal UT WY 500 1,500 425 2.00 40 890 593 8.90 $7Coal S Cal WY 500 1,500 1,500 2.30 100 3,550 2,367 8.90 $25Coal N Cal WY 500 1,500 1,600 2.30 100 3,780 2,520 8.90 $27 Coal NVSo WY 500 1,500 1,100 2.10 100 2,410 1,607 8.90 $17 Tar Sands OWI AB 500 DC 1,500 1,200 1.80 285 2,445 1,630 8.90 $18 Tar Sands S Cal AB 500 DC 2,000 1,730 1.70 380 3,321 1,661 8.90 $18Tar Sands AB AB 500 DC 500 475 2.00 95 1,045 2,090 8.90 $22Gas/Other N/A N/A N/A N/A N/A N/A N/A 16.80 $2 Dollars per KWTo From Line Size (KV)MilesCapacity (MW)$/MWh @ 100% CF Inter-regional Resource Type Inter-regional Inter-regional Fixed O&M $/KW/YRCost per Mile ($Mil)Substation Costs ($Mil)Total Capital Cost ($Mil) Appendix C177 7 Northwest Resource Options/LimitationsNorthwest Resource Options/Limitations Gas: •CCCT:No Limitations •SCCT:No Limitations Coal: •Local Pulverized:No more than 2 plants after 2010 •Imported Montana Pulverized:No Limitations •Local IGCC:No more than 5 plants after 2011 (2 max per year) •Imported Montana IGCC:No Limitations •Imported Montana IGCC w/ Seq: Limit 2 plants Wind: •Local:No more than 1,000MW of capacity without building new transmission •Imported:No limitations Other: •Geothermal:Limit 100 MW (2 plants) •Solar:Not available •Nuclear:Not available •Co-Gen:Limit 50 MW (2 plants) •Manure:Limit 2 MW (2 plants) •Landfill Gas:Limit 2 MW (2 plants) •Wood:Limit 50 MW (2 plants) •Tar Sands:Limit of 1,500MW after 2011 8 Western Interconnect Options/LimitationsWestern Interconnect Options/Limitations Gas: •CCCT:No Limitations •SCCT:No Limitations Coal: •Local Pulverized:No Limitations (Not allowed in California) •Imported Wyoming Pulverized:No Limitations with new transmission build (S. Cal allowed to build 1 plant in Utah by upgrading the IPP DC Interconnect) •Local IGCC:No Limitations (Not allowed in California) •Imported Wyoming IGCC:No Limitations with new transmission build •Local IGCC w/ Seq: No Limitations (Not allowed in California) •Imported Wyoming IGCC w/ Seq: No Limitations with new transmission build Wind: •Local:Requires transmission to be built Other: •Geothermal:100 MW per area (2 plants) •Solar:10 MW per area (5 plants) •Nuclear: 1,100 MW in Arizona •Co-Gen:Not available •Manure:Not available •Landfill Gas: Not available •Wood:Not available •Tar Sands:California & S. Nevada with a limit of 2,500 MW after 2011 Not available for modeling simplicity and speed Appendix C178 9 “PRELIMINARY”“PRELIMINARY” Electric Market ForecastsElectric Market Forecasts 10 Mid Columbia Electric Prices (Qr. Avg.)Mid Columbia Electric Prices (Qr. Avg.) $- $10 $20 $30 $40 $50 $60 $70 $80 $90 200720082009 20102011 2012201320142015 2016 2017201820192020 2021 2022202320242025 2026 Year $/ M W h Appendix C179 11 Marginal Heat RateMarginal Heat Rate 4 5 6 7 8 9 10 11 20 0 7 20 0 7 20 0 8 20 0 9 20 1 0 20 1 0 20 1 1 20 1 2 20 1 3 20 1 3 20 1 4 20 1 5 20 1 6 20 1 6 20 1 7 20 1 8 20 1 9 20 1 9 20 2 0 20 2 1 20 2 2 20 2 2 20 2 3 20 2 4 20 2 5 20 2 5 20 2 6 Year He a t R a t e D t h / M W h 12 Hourly Price CurvesHourly Price Curves $- $20 $40 $60 $80 $100 $120 $140 $160 $180 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Percent of the Year $/ M W h YR-2007 YR-2015 YR-2026 Appendix C180 13 Annual Electric ForecastsAnnual Electric Forecasts $30 $40 $50 $60 $70 $80 $90 20072008200920102011201220132014201520162017201820192020202120222023202420252026 $/ M W h COB SP15 WI MID-C 14 “PRELIMINARY”“PRELIMINARY” Capacity Expansion ResultsCapacity Expansion Results Appendix C181 15 What is Capacity Expansion?What is Capacity Expansion? Definition: Simulates the addition of new resources based on a set of resource attributes, capital and variable costs Seeks to find the least cost set of resources What does the AURORAXMP Expansion Logic Do? Creates a matrix of new resources and calculates its value compared to the market (~17,000 resources for studies shown today) on a present value basis Iterates until the optimal mix of generation is found (including resource type, timing, and location) Retires plants if plants that are no longer economic (retirement was not an option for the studies shown today) Renewable Portfolio Standards (RPS): AURORAXMP does not currently add resources to meet RPS requirements, for this IRP, RPS requirements were manually added based on the NPCC 5th Power Plan 16 Northwest Loads & ResourcesNorthwest Loads & Resources Annual Resource Availability for the Northwest Does not include Imports/Exports Year Load Resources Balance 2007 16,544 23,478 6,934 2008 16,842 23,478 6,636 2009 17,145 23,478 6,333 2010 17,454 23,478 6,024 2011 17,768 23,478 5,710 2012 18,088 23,478 5,390 2013 18,414 23,478 5,064 2014 18,745 23,478 4,733 2015 19,082 23,478 4,396 2016 19,425 23,478 4,053 2017 19,775 23,478 3,703 2018 20,131 23,478 3,347 2019 20,493 23,478 2,985 2020 20,862 23,478 2,616 2021 21,238 23,478 2,240 2022 21,620 23,478 1,858 2023 22,009 23,478 1,469 2024 22,405 23,478 1,073 2025 22,808 23,478 670 2026 23,219 23,478 259 Estimated Average Annual Net Position (aMW) - 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 20072008200920102011201220132014201520162017201820192020202120222023202420252026 aM W Appendix C182 17 Northwest New Resources SelectionNorthwest New Resources Selection Estimated Average Annual Northwest Position Annual Resource Selection (MW Capacity) Year CCCT SCCT Pul. Coal IGCC Coal Wind Total2007 0 2008 0 2009 0 2010 0 2011 800 8002012 02013 0 2014 0 2015 0 2016 425 4252017 425 4252018 02019 425 425 2020 425 425 2021 0 2022 425 4252023 610 100 7102024 100 100 2025 610 610 2026 200 200 Total 1,220 0 800 2,125 400 4,545 - 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 20072008200920102011201220132014201520162017201820192020202120222023202420252026 aM W Existing Resources With New Resources 18 Western Interconnect Resource SelectionWestern Interconnect Resource Selection Resource Begin Year CCCT- Gas SCCT- Gas IGCC- Coal Pulverized- Coal Wind Nuclear Total 2007 3,660 1,692 0 0 0 0 5,3522008 2,440 2,350 0 0 0 0 4,790 2009 1,830 376 0 0 0 0 2,206 2010 610 0 0 4,800 0 0 5,410 2011 3,660 376 0 3,600 0 0 7,636 2012 1,830 188 0 3,200 0 0 5,2182013 1,830 0 425 1,600 0 0 3,8552014 3,050 0 0 1,200 0 0 4,250 2015 1,220 0 0 800 0 0 2,020 2016 3,050 0 425 0 0 0 3,475 2017 3,050 0 850 0 100 0 4,000 2018 4,270 0 850 0 0 0 5,1202019 3,050 0 2,125 0 0 0 5,175 2020 1,830 94 1,700 0 0 1,100 4,724 2021 5,490 0 1,275 0 0 0 6,765 2022 3,050 94 1,275 0 0 0 4,419 2023 6,100 564 850 0 200 0 7,7142024 6,100 282 850 0 200 0 7,4322025 3,050 0 1,275 0 0 0 4,3252026 4,270 0 1,275 0 200 0 5,745 Total Capacity 63,440 6,016 13,175 15,200 700 1,100 99,631 % of Energy 69% 1% 13% 15% 0% 1% 100% Appendix C183 19 New Resources for the Western Interconnect New Resources for the Western Interconnect Includes RPSIncludes RPS 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 Year MW o f C a p a c i t y RPS Total 20 Total New Resource Capacity (2007Total New Resource Capacity (2007--2026)2026) (Shown in (Shown in GigawattsGigawatts)) 5.1 2.0 2.9 5.3 4.6 5.12.1 16.42.5 9.3 5.2 22.9 28.6 400MW 1700MW 100MW Appendix C184 ModelingModeling Futures and ScenariosFutures and Scenarios 2005 Integrated Resource Plan Fifth Technical Advisory Committee Meeting March 23, 2005 John Lyons 2 Presentation OverviewPresentation Overview • Definition Of A Future 3 • Definition Of A Scenario 4 • Uses For Futures/Scenarios 5 • Revised List of Scenarios 6 - 7 • List of Futures 8 Slide # Appendix C185 3 Definition Of A FutureDefinition Of A Future A FUTURE is modeled stochastically. Avista will model its options over 20 years with up to 300 Monte Carlo draws of varying hydro, load, gas, and wind conditions. Advantages: ability to quantitatively assess risk in addition to the expected base value Disadvantage: long solution times (8 CPUs for up to a week), and results of a specific change can be more difficult to comprehend 4 A SCENARIO is not modeled stochastically. Instead we will use average forecasts of hydro, load, gas, and wind generation to simulate the impact of a major change in a single assumption. Advantages: faster solution time (1 CPU for 5 hours), easier to understand impacts of the change Disadvantage: unable to quantitatively assess risk of market volatility Definition Of A ScenarioDefinition Of A Scenario Appendix C186 5 Uses For Futures/ScenariosUses For Futures/Scenarios • Understand Potential Future Impacts And Their Magnitudes On: – Wholesale marketplace – Different resource options – Avista’s existing portfolio of loads & resources – The Preferred Resource Strategy 6 Revised List of ScenariosRevised List of Scenarios • High Gas * – Increase prices 50% to ~$9/dth • Low Gas * – Decrease prices 50% to ~ $3/dth • Emissions 2 * – $25/ton CO2 • Low Transmission * – Reduce transmission capital costs by 33% • High Wind Penetration – 5,000 MW NW wind replaces other new resources • Energy Market Bubbles – Electricity market mimics real estate building cycles • Loss of Large AVA Plant – Noxon “lost” for 5 years • High AVA Load – Double load growth to ~4% • Low AVA Load – No load growth • WECC-Wide Renewable Portfolio Standard – 25% renewables by end of study, replacing other new resources * Indicates new capacity expansion run will be required Appendix C187 7 Revised List of ScenariosRevised List of Scenarios • Long Haul Coal – Site a new coal plant within our service territory and rail in coal • Fundamental Hydro Shift * – Recent drought becomes new average (90% of mean value) • Green Growth Initiative – All new Avista resources are renewable • Double Avista DSM – Double the amount of DSM acquisition • Loss of Spokane River Projects – Current negotiations for relicensing fail and all projects on Spokane River are lost * Indicates new capacity expansion run will be required 8 List of FuturesList of Futures •Base Case – All Base Case assumptions included •Volatile Gas Prices – Double base case volatility (sigma) from 50% of mean to 100% of mean – Remaining Base Case assumptions unchanged •Emissions Case – Based on the McCain Lieberman Bill – Remaining Base Case assumptions unchanged Appendix C188 1 2005 Draft IRP Outline2005 Draft IRP Outline 2005 Integrated Resource Plan Fifth Technical Advisory Committee Meeting March 23, 2005 John Lyons 2 2005 Draft IRP Outline2005 Draft IRP Outline • The format of the 2003 IRP will be used as a template for the final draft of the 2005 IRP • Will be published in two parts: main report & technical appendix • Please let us know if there were any portions of the 2003 IRP that you want to see again, do not want to see again, or thought should have been included in the 2003 IRP. Appendix C189 3 2005 Draft IRP Outline2005 Draft IRP Outline Section 1: Introduction & Summary • Outline of the IRP process Section 2: Loads & Resources • Generating assets and long term contracts • Load forecasts, energy & capacity positions • Planning reserves and sustained capacity • Wind capacity and forecasting Section 3: Demand-Side Management • Past and future activities • DSM in AURORA 4 2005 Draft IRP Outline2005 Draft IRP Outline Section 4: New Resource Alternatives • Approach, resources considered and resources not evaluated Section 5: Modeling • Modeling process • Assumptions and Inputs • Analysis of futures and scenarios Section 6: Risk Analysis • Stochastic risk analysis • Risk and benefit analysis of resource options Appendix C190 5 2005 Draft IRP Outline2005 Draft IRP Outline Section 7: Results • Market prices and volatility for the Western Interconnect • Preferred resource strategy • Comparisons of strategies and scenarios • Efficient frontiers Section 8: Action Plans & Avoided Costs 6 2005 Draft IRP Outline2005 Draft IRP Outline • Questions? • Any sections that you would like to see included or excluded from the IRP? Appendix C191 1 Gas & Inflation Forecast Gas & Inflation Forecast UpdateUpdate 2005 Integrated Resource Plan Sixth Technical Advisory Committee Meeting May 18, 2005 James Gall 2 Natural Gas Price & Inflation Assumptions Natural Gas Price & Inflation Assumptions and Caveatsand Caveats • Global Insight, Inc. Winter 2005 Long Term Forecast Contract with Avista Corp. – March 2005 30-year forecast was received on April 4, 2005 – Avista Corp. subscription with Global Insight parameters for usage of Global Insight’s data • Avista may use Global Insight information with attribution, and other parties may cite Avista information with attribution to Global Insight, although other parties may not privately use Avista or Global Insight information • Avista has permission to use Global Insight’s information to develop Avista-specific projections for Company use – Avista uses Global Insight inflation forecasts directly • Avista is responsible for interpreting how Avista perceives Global Insight’s inflation forecasts have changed between 2004 and 2005 • The 2005 inflation forecast compared with the 2004 inflation forecast is slightly higher in the near term, and substantially lower in the long term (see slide), averaging 2.3% compared to the previous 3.0% – Avista uses Global Insight natural gas producer price index forecast escalation to create Avista’s own forecast of natural gas prices Appendix C192 3 Natural Gas Price & Inflation Assumptions Natural Gas Price & Inflation Assumptions and Caveats and Caveats (Cont.)(Cont.) • Avista’s 2005 long term natural gas price forecast has been updated in April 2005 – Avista has used NYMEX forward prices from April 6, 2005 to prepare natural gas prices for 2005 through 2010, inclusive. – After 2010, Avista has applied natural gas price escalation rates to the 2010 forward price to obtain forecasts for natural gas prices for the period 2011 through 2035, inclusive – This estimate replaces a forecast prepared in July 2004, which used July 1, 2004 forward prices for 2004 through 2007, and applied Global Insight’s March 2005 natural gas price escalation forecast – The NYMEX forward prices for April 6, 2005 are considerably higher than the July 1, 2004 forwards – Global Insight’s forecast for natural gas price escalation is higher in the near term, and lower in the long term, but after adjusting for inflation, there is little change after 2010 in real prices 4 $4 $5 $6 $7 $8 $9 $10 $11 2005 2008 2011 2014 2017 2020 2023 2026 Year $/D e c a t h e r m March 2004 Forecast March 2005 Forecast Henry Hub Gas ForecastsHenry Hub Gas Forecasts Real DollarsReal Dollars Forward market Forw a r d m a r k e t Global Insight’s Gas Escalation Rates Global Insight’s Gas Escalation Rates The 2005 forecast is higher until 2010, after which prices are essentially the same on a real dollar basis. Appendix C193 5 Henry Hub Gas ForecastsHenry Hub Gas Forecasts Nominal DollarsNominal Dollars Basin differentials remain the same as presented at the February 2005 TAC Meeting $4 $5 $6 $7 $8 $9 $10 $11 2005 2008 2011 2014 2017 2020 2023 2026 Year $/ D e c a t h e r m March 2005 Forecast March 2004 Forecast Slide 4 indicated that real prices between 2011-2026 were the same, although the 2005 inflation forecast the nominal gas prices begin to separate in 2012. 6 Annual Inflation RatesAnnual Inflation Rates - 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 2005 2008 2011 2014 2017 2020 2023 2026 Year Pe r c e n t I n f l a t i o n March 2005 Forecast March 2004 Forecast The 2005 inflation forecast is near the same for the near term, although long term inflation is not as high (~3.5% to ~2.5%). Appendix C194 7 Value of $100 as it Grows with InflationValue of $100 as it Grows with Inflation Nominal DollarsNominal Dollars 3.0% Annualized Growth Rate 2.3% Annualized Growth Rate $100 $110 $120 $130 $140 $150 $160 $170 $180 $190 $200 2005 2008 2011 2014 2017 2020 2023 2026 Year Va l u e o f $ 1 0 0 March 2005 Forecast March 2004 Forecast The 22 year annual average inflation estimate is lower, 3.0% to 2.3%. 8 TakeTake--AwaysAways • April 2005 forecast is more in-line with current forward gas markets • Medium-term gas prices are higher then previous forecast • Long-term gas prices are lower nominally, but the same in real dollars • Long-term inflation is lower Appendix C195 1 Base Case ResultsBase Case Results-- Electric Price ForecastElectric Price Forecast 2005 Integrated Resource Plan Sixth Technical Advisory Committee Meeting May 18, 2005 James Gall 2 Topics of InterestTopics of Interest Deterministic Modeling Western Interconnect Capacity Expansion Results Electric Market Prices Stochastic Modeling Sample Size Base Case Results Volatile Gas Results Net Power Costs Resource Values Appendix C196 3 Capacity Expansion ResultsCapacity Expansion Results 4 What is Capacity Expansion?What is Capacity Expansion? Definition: Simulates the addition of new resources based on a set of resource attributes, capital and variable costs Seeks to find the least cost set of resources What does the AURORAXMP Expansion Logic Do? Creates a matrix of new resources and calculates its value compared to the market (~17,000 resources for studies shown today) on a present value basis Iterates until the optimal mix of generation is found (including resource type, timing, and location) Retires plants if they are no longer economic (retirement was not an option for the studies shown today) Renewable Portfolio Standards (RPS): AURORAXMP does not currently add resources to meet RPS requirements, for this IRP, RPS requirements were manually added based on NPCC 5th Power Plan approach Why is this all necessary? Without a forecasted set of new resource the market price forecast will be useless! Appendix C197 5 Western Interconnect New Resource MixWestern Interconnect New Resource Mix Other 1% SCCT 6% Wind 6% Coal 12% Fixed RPS 10% CCCT 65% 114 GW of Installed Capacity No new CCCT in the NW until 2023 6 Total New Resources (2007Total New Resources (2007--2026)2026) (Shown in GW Capacity, excludes RPS Resources)(Shown in GW Capacity, excludes RPS Resources) 4.5 .4 .4 10.8 8.4 19.2 24.7 4.5 .9 2.4 3.1 1.2 9.7 2.3 3.5 5.7 2.1 Appendix C198 7 Cumulative New Resources for the Western Interconnect Cumulative New Resources for the Western Interconnect 0 20,000 40,000 60,000 80,000 100,000 120,000 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 MW o f C a p a c i t y RPS- Fixed Wind SCCT Other Coal CCCT 8 - 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 20072008200920102011201220132014201520162017201820192020202120222023202420252026 aM W Existing Resources New Resources NW Surplus Energy & New Resource SelectionNW Surplus Energy & New Resource Selection 800 MW- Coal 1,000 MW- Wind 1,220 MW- CCCT 500 MW- Wind Appendix C199 9 Electric Price ForecastsElectric Price Forecasts 10 Mid Columbia Electric Prices Mid Columbia Electric Prices Shown in Nominal Dollars per MWhShown in Nominal Dollars per MWh $0 $10 $20 $30 $40 $50 $60 $70 $80 $90 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 $/M W h Max Annual On Peak Avg Annual Avg Annual Off Peak Avg Min Appendix C200 11 How Do We Compare to Our Peers at Mid C?How Do We Compare to Our Peers at Mid C? Shown in Nominal Dollars per MWhShown in Nominal Dollars per MWh $25 $30 $35 $40 $45 $50 $55 $60 $65 $70 $/M W h ( A n n u a l A v g . ) PSE 2005 $43 $39 $34 $31 $35 $39 $42 $47 $49 $46 $47 $51 $52 $51 $54 $55 $59 $62 $65 PAC 2004 $46 $41 $41 $43 $43 $43 $44 $46 $47 $49 $50 $51 $52 $55 $58 $59 $60 AVA 2005 $50 $46 $44 $42 $42 $40 $41 $41 $43 $44 $45 $47 $49 $50 $51 $52 $54 $54 $56 $57 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 12 Regional Electric Market PricesRegional Electric Market Prices Shown in Nominal Annual Average Dollars per MWhShown in Nominal Annual Average Dollars per MWh $35 $40 $45 $50 $55 $60 $65 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 $/ M W h MID C NCAL SCAL SNV Appendix C201 13 Stochastic ResultsStochastic Results 14 Choosing a Sample SizeChoosing a Sample Size What is the right sample size to use? 50, 100, 200, or 300 At the March TAC meeting we indicated that a sample size of 300 was our target Analysis: 300 draws of Gas Prices, Hydro Conditions, Wind Shapes, and Load Forecasts were simulated in AURORA to create 300 market price forecasts The mean & standard deviations of certain resource values were compared to each other using a random draw of 10, 25, 50, 100, 150, 200, and 300 iterations The results of 200 & 300 iterations were nearly identical Appendix C202 15 Comparison of Resource ValuesComparison of Resource Values 80% 85% 90% 95% 100% 105% 110% 115% 120% 125% 130% 10 25 50 100 150 200 300 Number of Iterations Sa m p l e M e a n / P o p u l a t i o n M e a n CT-Frame IGCC Coal CCCT-AVA Wind-OWI T1 Wind-Ken T1 TarSands Northeast AVA Portfolio AVA Load Only 16 Monthly Price DifferencesMonthly Price Differences Iterations OWI SP15 AZ UT 50 8.2% 8.9% 8.8% 8.3% 75 6.6% 6.9% 6.8% 6.6% 100 5.6% 5.7% 5.7% 5.7% 150 4.0% 4.0% 3.9% 4.1% 175 3.1% 3.0% 3.0% 3.1% 200 2.7% 2.7% 2.7% 2.7% Iterations OWI SP15 AZ UT 50 2.0% 1.7% 2.0% 2.0% 75 1.6% 1.3% 1.5% 1.5% 100 1.2% 1.0% 1.2% 1.2% 150 0.9% 0.8% 0.9% 0.9% 175 0.7% 0.6% 0.7% 0.7% 200 0.6% 0.5% 0.6% 0.6% Monthly Market Price Mean Absolute Difference from 300 Iterations Monthly Market Price Standard Devation Absolute Difference from 300 Iterations Market Price Sample Size Analysis Appendix C203 17 Base Case ResultsBase Case Results 18 Deterministic vs. Stochastic Mid C PricesDeterministic vs. Stochastic Mid C Prices Shown in Nominal Dollars per MWhShown in Nominal Dollars per MWh $30 $35 $40 $45 $50 $55 $60 $65 $70 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 $/ M W h Deterministic Prices Stochastic Prices Average difference in results is ~$1.25 or 2.6% Appendix C204 19 Mid Columbia Annual Average PricesMid Columbia Annual Average Prices Shown in Nominal Dollars per MWhShown in Nominal Dollars per MWh $25 $35 $45 $55 $65 $75 $85 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 $/ M W h Max 80% CI High Mean 80% CI Low Min 20 Volatile Gas ResultsVolatile Gas Results Appendix C205 21 Henry Hub Natural Gas Price ComparisonHenry Hub Natural Gas Price Comparison Base Case vs. Volatile Gas Case (Shown in Nominal Dollars per DeBase Case vs. Volatile Gas Case (Shown in Nominal Dollars per Decatherm)catherm) $4 $6 $8 $10 $12 $ p e r D e c a t h e r m Base- Mean 7.37 6.92 6.41 6.01 6.07 6.15 6.29 6.42 6.62 6.81 6.97 7.10 7.39 7.57 7.66 7.89 8.04 8.07 8.39 8.60 Volatile- Mean 7.47 6.97 6.44 5.83 5.91 6.16 6.27 6.45 6.80 7.02 6.98 7.08 7.31 7.37 7.69 8.00 7.89 8.35 8.60 8.54 Base- 80% CI High 8.47 7.86 7.31 6.90 6.99 7.04 7.23 7.36 7.53 7.85 7.93 8.13 8.54 8.65 8.80 9.09 9.31 9.29 9.67 9.86 Volatile- 80% CI High 9.76 9.05 8.21 7.28 7.52 8.03 7.86 8.15 8.54 9.01 8.86 9.21 9.56 9.45 9.87 10.43 10.13 10.79 11.33 10.96 Base- 80% CI Low 6.28 5.98 5.52 5.12 5.15 5.25 5.34 5.47 5.71 5.76 6.01 6.07 6.25 6.48 6.52 6.70 6.77 6.86 7.10 7.33 Volatile- 80% CI Low 5.19 4.88 4.67 4.39 4.30 4.28 4.68 4.75 5.06 5.04 5.11 4.94 5.07 5.30 5.51 5.57 5.65 5.91 5.87 6.12 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 22 Mid Columbia Annual Average PricesMid Columbia Annual Average Prices--Volatile GasVolatile Gas Shown in Nominal Dollars per MWhShown in Nominal Dollars per MWh $0 $20 $40 $60 $80 $100 $120 $140 $160 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 $/ M W h Max 80% CI High Mean 80% CI Low Min Appendix C206 23 Mid Columbia Annual Average Price ComparisonMid Columbia Annual Average Price Comparison Base Case vs. Volatile Gas Case (Shown in Nominal Dollars per MWBase Case vs. Volatile Gas Case (Shown in Nominal Dollars per MWh)h) $20 $30 $40 $50 $60 $70 $80 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 $/ M W h Volatile- 80% CI High Volatile- Mean Volatile- CI Low Base- 80% CI High Base- Mean Base- 80% CI Low 24 Distribution of Net Power Distribution of Net Power CostsCosts Appendix C207 25 Net Power CostsNet Power Costs--No Change to ResourcesNo Change to Resources 200 Iterations200 Iterations 0 10 20 30 $1,900 $2,150 $2,400 $2,650 $2,900 NPV (Millions) Fr e q u e n c y Base Case Volatile Gas Mean $2,348 26 NPCNPC--If All AVA Load Was Served by MarketIf All AVA Load Was Served by Market 200 Iterations200 Iterations 0 10 20 30 $4,000 $4,500 $5,000 $5,500 $6,000 NPV (Millions) Fr e q u e n c y Base Case Volatile Gas Mean $4,873 Appendix C208 27 Side by SideSide by Side 200 Iterations200 Iterations 0 10 20 30 40 50 $1,900 $2,400 $2,900 $3,400 $3,900 $4,400 $4,900 $5,400 $5,900 NPV (Millions) Fr e q u e n c y AVA NPC with Current Resources AVA NPC with No Resources 28 Resource Value ComparisonResource Value Comparison Appendix C209 29 1 MW Resource Value (excludes Capital Costs)1 MW Resource Value (excludes Capital Costs) MT Pulv. Coal (200 iterations) 0 10 20 30 40 50 60 $0 $875 $1,750 $2,625 $3,500 NPV (Thousands) Fr e q u e n c y Base Case Volatile Gas Mean 2,683 30 MT IGCC Coal (200 iterations) 0 10 20 30 40 50 60 $0 $875 $1,750 $2,625 $3,500 NPV (Thousands) Fr e q u e n c y Base Case Volatile Gas 1 MW Resource Value (excludes Capital Costs)1 MW Resource Value (excludes Capital Costs) Mean 2,718 Appendix C210 31 OWI Pulv. Coal (200 iterations) 0 10 20 30 40 50 60 $0 $875 $1,750 $2,625 $3,500 NPV (Thousands) Fr e q u e n c y Base Case Volatile Gas 1 MW Resource Value (excludes Capital Costs)1 MW Resource Value (excludes Capital Costs) Mean 2,219 32 Tar Sands (200 iterations) 0 10 20 30 40 50 60 $0 $875 $1,750 $2,625 $3,500 NPV (Thousands) Fr e q u e n c y Base Case Volatile Gas 1 MW Resource Value (excludes Capital Costs)1 MW Resource Value (excludes Capital Costs) Mean 648 Appendix C211 33 CCCT (200 iterations) 0 10 20 30 40 50 60 $0 $875 $1,750 $2,625 $3,500 NPV Fr e q u e n c y Base Case Volatile Gas (Thousands) 1 MW Resource Value (excludes Capital Costs)1 MW Resource Value (excludes Capital Costs) Mean 158 0 5 10 15 20 $90 $114 $138 $162 $186 $210 NPV Fre q u e n c y 34 OWI Wind Tier 1 (200 iterations) 0 10 20 30 40 50 60 $0 $875 $1,750 $2,625 $3,500 NPV (Thousands) Fr e q u e n c y Base Case Volatile Gas 1 MW Resource Value (excludes Capital Costs)1 MW Resource Value (excludes Capital Costs) Mean 1,079 Appendix C212 35 MT Wind Tier 1 (200 iterations) 0 10 20 30 40 50 60 $0 $875 $1,750 $2,625 $3,500 NPV (Thousands) Fr e q u e n c y Base Case Volatile Gas 1 MW Resource Value (excludes Capital Costs)1 MW Resource Value (excludes Capital Costs) Mean 1,277 36 Geothermal (200 iterations) 0 10 20 30 40 50 60 $0 $875 $1,750 $2,625 $3,500 NPV (Thousands) Fr e q u e n c y Base Case Volatile Gas 1 MW Resource Value (excludes Capital Costs)1 MW Resource Value (excludes Capital Costs) Mean 2,034 Appendix C213 37 TakeTake--AwaysAways New Generation over the next 20+ years is forecasted to be primarily Gas, Coal and Wind for the Western Interconnect, unless there is a shift in technology The Northwest is best suited for new coal and wind generation over the next 10-15 years The Mid Columbia electric market is expected to be correlated to natural gas prices, with the exception of Q2 The current Avista generation fleet nearly cuts in half the cost of generation supply, compared to an Avista Gen-Co. The preferred resource strategy will continue to lower these costs and reduce risk New gas plants do not hold much value (ignoring capital requirements), but the value is less volatile (market price is not much different the generation cost) Appendix C214 1 LP Module, the Selection LP Module, the Selection Criteria & Efficient FrontierCriteria & Efficient Frontier 2005 Integrated Resource Plan Fifth Technical Advisory Committee Meeting May 18, 2005 Clint Kalich 2 LP Module Data SourcesLP Module Data Sources • Portfolio Output from AURORA Runs – Margin generated in each studied year – 20 year x 200 matrix of value • Avista’s current portfolio • each new resource option • Load Requirements – Both capacity and energy by year • Reduced by DSM and hydro upgrades • Resource Capital Costs from NPCC – Transmission costs added where required Appendix C215 3 LP Module Optimization RoutineLP Module Optimization Routine • Match Load Growth With Best Resources • Weight First 10 Years of Study Heaviest • Optimization For Mix of Low Cost and Low Risk • Generate “Efficient Frontier” – Visual Basic code automates its creation – Illustrates trade-offs graphically • Cost, risk, capital requirements – Helps Avista determine an optimal mix 4 Limits Imposed on LP RoutineLimits Imposed on LP Routine • 650 MW of Wind Over 20 Years – AVA share of NW wind estimate (250 MW) – Assume similar amount from E. Montana – Another 150 MW in Avista service territory • Market Available for Short-Term Balancing • Meet Both Energy and Capacity Needs – Cannot plan for more than capacity needs Appendix C216 5 Build ExampleBuild Example––Capacity & EnergyCapacity & Energy - 100 200 300 400 500 600 700 800 900 1,000 20 0 7 20 0 8 20 0 9 20 1 0 20 1 1 20 1 2 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 me g a w a t t s Capacity Need Energy Need Capacity Built Energy Built 6 Power Supply Cost IllustrationPower Supply Cost Illustration——20162016 (1 7 0 ) (1 5 4 ) (1 3 8 ) (1 2 2 ) (1 0 6 ) (9 0 ) (7 4 ) (5 8 ) (4 2 ) (2 6 ) (1 0 ) 6 22 38 54 70 86 10 2 11 8 13 4 15 0 16 6 $millions per year Lowest Cost Statistics ($millions) Mean 337.8 StDev 43.4 Covariance 13% 10-Year NPV (2007$) 1,467 10-Year Capital 244 2016 Coal%Capacity 0% 2016 Wind%Capacity 0% 2016 Gas%Capacity 97% Lowest Risk Statistics ($millions) Mean 514.4 StDev 25.0 Covariance 5% 10-Year NPV (2007$) 2,119 10-Year Capital 1,892 2016 Coal%Capacity 82% 2016 Wind%Capacity 15% 2016 Gas%Capacity 0% Appendix C217 7 LP ModuleLP Module——Illustration 1 Lowest CostIllustration 1 Lowest Cost 100.0 COST 0.0 RISK Resource Selection Optimizer Optimized Resource Mix Capacity 0 200 400 600 800 1,000 1,200 20 0 7 20 0 9 20 1 1 20 1 3 20 1 5 20 1 7 20 1 9 20 2 1 20 2 3 20 2 5 av e r a g e m e g a w a t t s Coal CCCTSCCTWindOtherTarSands * wind is shown at installed capability, not peak capacity contribution Optimized Resource Mix Energy 0 100 200 300 400 500 600 700 800 900 20 0 7 20 0 9 20 1 1 20 1 3 20 1 5 20 1 7 20 1 9 20 2 1 20 2 3 20 2 5 av e r a g e m e g a w a t t s Coal CCCTSCCTWindOtherTarSands 8 LP ModuleLP Module——Illustration 2 Lowest RiskIllustration 2 Lowest Risk 0.0 COST 100.0 RISK Resource Selection Optimizer Optimized Resource Mix Capacity 0 200 400 600 800 1,000 1,200 1,400 20 0 7 20 0 9 20 1 1 20 1 3 20 1 5 20 1 7 20 1 9 20 2 1 20 2 3 20 2 5 av e r a g e m e g a w a t t s Coal CCCTSCCTWindOtherTarSands * wind is shown at installed capability, not peak capacity contribution Optimized Resource Mix Energy 0 100 200 300 400 500 600 700 800 900 20 0 7 20 0 9 20 1 1 20 1 3 20 1 5 20 1 7 20 1 9 20 2 1 20 2 3 20 2 5 av e r a g e m e g a w a t t s Coal CCCTSCCTWindOtherTarSands Appendix C218 9 LP ModuleLP Module——Illustration 3 50/50 MixIllustration 3 50/50 Mix 50.0 COST 50.0 RISK Resource Selection Optimizer Optimized Resource Mix Capacity 0 200 400 600 800 1,000 1,200 1,400 20 0 7 20 0 9 20 1 1 20 1 3 20 1 5 20 1 7 20 1 9 20 2 1 20 2 3 20 2 5 av e r a g e m e g a w a t t s Coal CCCTSCCTWindOtherTarSands * wind is shown at installed capability, not peak capacity contribution Optimized Resource Mix Energy 0 100 200 300 400 500 600 700 800 900 20 0 7 20 0 9 20 1 1 20 1 3 20 1 5 20 1 7 20 1 9 20 2 1 20 2 3 20 2 5 av e r a g e m e g a w a t t s Coal CCCTSCCTWindOtherTarSands 10 LP ModuleLP Module——Illustration 4 25/75 MixIllustration 4 25/75 Mix 25.0 COST 75.0 RISK Resource Selection Optimizer Optimized Resource Mix Capacity 0 200 400 600 800 1,000 1,200 1,400 20 0 7 20 0 9 20 1 1 20 1 3 20 1 5 20 1 7 20 1 9 20 2 1 20 2 3 20 2 5 av e r a g e m e g a w a t t s Coal CCCTSCCTWindOtherTarSands * wind is shown at installed capability, not peak capacity contribution Optimized Resource Mix Energy 0 100 200 300 400 500 600 700 800 900 20 0 7 20 0 9 20 1 1 20 1 3 20 1 5 20 1 7 20 1 9 20 2 1 20 2 3 20 2 5 av e r a g e m e g a w a t t s Coal CCCTSCCTWindOtherTarSands Appendix C219 11 LP ModuleLP Module——Illustration 5 75/25 MixIllustration 5 75/25 Mix 75.0 COST 25.0 RISK Resource Selection Optimizer Optimized Resource Mix Capacity 0 200 400 600 800 1,000 1,200 1,400 20 0 7 20 0 9 20 1 1 20 1 3 20 1 5 20 1 7 20 1 9 20 2 1 20 2 3 20 2 5 av e r a g e m e g a w a t t s Coal CCCTSCCTWindOtherTarSands * wind is shown at installed capability, not peak capacity contribution Optimized Resource Mix Energy 0 100 200 300 400 500 600 700 800 900 20 0 7 20 0 9 20 1 1 20 1 3 20 1 5 20 1 7 20 1 9 20 2 1 20 2 3 20 2 5 av e r a g e m e g a w a t t s Coal CCCTSCCTWindOtherTarSands 12 Efficient FrontierEfficient Frontier––TradeTrade--Offs Between Offs Between Power Supply Expense, Capital, RiskPower Supply Expense, Capital, Risk 1,450 1,500 1,550 1,600 1,650 1,700 1,750 1,800 1,850 6. 5 % 7. 0 % 7. 5 % 8. 0 % 8. 5 % 9. 0 % 9. 5 % 10 . 0 % 10 . 5 % 11 . 0 % 11 . 5 % 12 . 0 % covariance (stdev/mean) po w e r s u p p l y e x p e n s e (1 0 - y e a r N P V $ m i l l i o n s ) 0 150 300 450 600 750 900 1,050 1,200 Ca p i t a l C o s t (n o m i n a l $ m i l l i o n s ) Power Supply Expense Capital Cost 50%C/50%R 25%C/50%R 75%C/25%R Appendix C220 13 Resource Builds of Efficient FrontierResource Builds of Efficient Frontier 2016 0 75 150 225 300 375 450 525 600 675 750 6.7 6 % 6.7 5 % 6.7 5 % 6.8 5 % 6.9 5 % 6.9 5 % 6.9 5 % 8.2 7 % 8.2 7 % 8.2 7 % 8.2 7 % 8.2 7 % 8.9 7 % 8.9 9 % 8.9 9 % 9.0 3 % 9.0 3 % 9.0 9 % 9.2 4 % 9.7 5 % 11 . 8 9 % covariance (stdev/mean) me g a w a t t s ( t h r u 2 0 1 6 ) 0 225 450 675 900 1,125 1,350 1,575 1,800 2,025 2,250 Ca p i t a l R e q u i r e m e n t & Po r t f o l i o C o s t ( $ m i l l i o n s ) COAL WIND OTHER RENEW GAS CT GAS CCCT TAR SANDS 10-Year Capital Requirement (NPV) Right Axis 10-Year Portfolio Cost (NPV) Right Axis 14 Preliminary ObservationsPreliminary Observations • Lowest Cost Heavily Dependent on Peaking Gas Turbines – Implies heavy reliance on spot market • Lowest Risk Includes More Wind and Coal – Capital costs likely are significant – $1.2B over 7 years • Preferred Resource Strategy (PRS) will likely consist of balanced mix of coal, gas and wind – Biomass (animal waste) has potential, too Appendix C221 15 Next StepsNext Steps • Refine PRS With Complete Datasets • Compare Alternative Builds to Efficient Frontier • Select Point on Efficient Frontier – Considering capital cost power supply expense & risk factors – Account for “lumpiness” of resource additions 16 Comments/SuggestionsComments/Suggestions Appendix C222 Avista Corporation Estimated Resource Integration Costs for the 2005 IRP April 29, 2005 Scott A. Waples Introduction: The Avista Merchant has requested integration costs for various resources that they might acquire in the future. Points of integration are critical for this discussion; however although these resources vary in fuel type, the type of generation is not material for much of this discussion and will be considered only when necessary (when, as in some wind or biomass development, 1000 MW in one facility is not likely). Various integration points for new generation will be discussed below. It should be noted that rigorous study has not been completed for any of these alternatives (engineering judgment only), thus the costs provided are not of a “construction estimate” quality. Also note that as the size of the resource to be integrated increases, the certainty of the estimates becomes more suspect. A 50 MW resource can be integrated in many places on our (or other) systems. 350 MW can be integrated in specific areas, 750 MW in fewer; and at the high end- 1000 MW of new resource- a generic integration cost of $1.5 billion has been assigned due to the uncertainty of impacts to the Avista system (and/or its neighboring systems). Should it become clear that Avista requires that size of resource, a detailed regional process would be undertaken to determine the exact impacts and integration costs. Colstrip: The present transmission system to the west of (and serving) the Colstrip generating complex is a double circuit 500 kV line. A regional study under the auspices of the Northwest Power Pool (NWPP) NTAC committee is presently underway to determine rough integration costs for such a project. Those studies are not yet complete, so the following estimates are subject to revision in the near future. • 350 MW: It is expected that to integrate 350 MW at Colstrip, a 500 kV series capacitors and other reinforcements would be required. Cost: Approximately $100M. • 750 MW: It is expected that to integrate 750 MW at Colstrip, 500 kV series capacitors and other reinforcements (including 230 kV reinforcements in Eastern Washington) would be required. Cost: Approximately $400M. • 1000 MW: It is expected that major new 500 kV facilities would be required to integrate this capacity at Colstrip. Cost: Approximately $1.5B. Appendix C223 Alberta Oil Sands, Mid Columbia Purchase, Nuclear Purchase, Kennewick Wind: Presently there is no suitable method of integrating energy from the Alberta oil sands into the Avista system. Because of the distances involved, integration into the United States power grid at capacity levels less than 3000 MW is unlikely. Because of the capacity required for the economics of the project to “pencil”, it is anticipated that transmission from the oil sands would be a Direct Current 500 kV line. We assume that one of the DC terminals would be at the Mid Columbia. Avista could then purchase portions of this energy to be delivered to its system from that market hub. It should be noted that a regional scoping effort is presently being undertaken to more closely estimate costs for this project, and thus these estimates should change in the near future. The Mid Columbia Purchase option should be no different than the Oil Sands integration. Similarly, it is expected that power from a new nuclear plant would be delivered at the Mid Columbia for delivery into the Avista system. • 350 MW: Estimated Cost: $100M. • 750 MW: Estimated Cost: $150M. • 1000 MW: Cost: Approximately $600-800M. Rosalia: The present transmission system serving the Rosalia, Washington, area is a low capacity 115 kV line. It might be suitable for integration of 40-50 MW in its present configuration, however by the end of 2007, this line will be reconstructed to a high capacity 230 kV line. • 350 MW: It is expected that to integrate 350 MW at Rosalia, very little new transmission would be required. Cost: Approximately $10M. • 750 MW: It is expected that to integrate 350 MW at Sprague, additional 230 kV reinforcement would be required in the Avista system. Cost: Approximately $80M. • 1000 MW: It is expected that major new 500 kV facilities would be required to integrate this capacity at Sprague. Cost: Approximately $1.5B. Rathdrum: The present transmission system serving the Rathdrum, Idaho, area is a high capacity double circuit 230 kV line. • 350 MW: It is expected that to integrate 350 MW at Rathdrum, very little new transmission would be required. Cost: Approximately $20M. • 750 MW: It is expected that to integrate 350 MW at Rathdrum, additional 230 kV reinforcement would be required in the Avista system. Cost: Approximately $70M. • 1000 MW: It is expected that major new 500 kV facilities would be required to integrate this capacity at Rathdrum. Cost: Approximately $1.5B. Appendix C224 Sprague: The present transmission system serving the Sprague, Washington, area is a low capacity 115 kV line. This line might be suitable for integration of 40-50 MW in its present configuration, however new 230 kV construction would be required for any larger amount of generation. • 350 MW: It is expected that to integrate 350 MW at Sprague, a double circuit 230 kV line would be constructed between the plant and the Spokane area. Cost: Approximately $50M. • 750 MW: It is expected that to integrate 350 MW at Sprague, a high capacity double circuit 230 kV line would be constructed between the plant and the Spokane area. Additional transmission would be required between the site and the Mid Columbia. Cost: Approximately $100M. • 1000 MW: It is expected that major new 500 kV facilities would be required to integrate this capacity at Sprague. Cost: Approximately $1.5B. Eastern Montana Wind: The present transmission system to the west of (and serving) the present generation in Montana is a double circuit 500 kV line. A regional study under the auspices of the Northwest Power Pool (NWPP) NTAC committee is presently underway to determine rough integration costs for wind integration from eastern Montana. Those studies are not yet complete, so the following estimates are subject to revision in the near future. • 350 MW: It is expected that to integrate 350 MW at Sprague, a double circuit 230 kV line would be constructed between the plant and the Spokane area. Cost: Approximately $150M. • 750 MW: It is expected that to integrate 350 MW at Sprague, a high capacity double circuit 230 kV line would be constructed between the plant and the Spokane area. Additional transmission would be required between the site and the Mid Columbia. Cost: Approximately $450M. • 1000 MW: It is expected that major new 500 kV facilities would be required to integrate this capacity at Sprague. Cost: Approximately $1.5B. Othello Area Wind Project sizes of between 80-150 MW have been proposed for the Othello area. Depending upon the final project size, location, and timing, integration costs could vary from $10M to $70M. Detailed studies would need to be completed to optimize the transmission in this area if this wind development were to occur. Appendix C225 Nevada Geothermal: Generation from Nevada would have to be wheeled over other systems. Costs for this alternative is not known. Landfill Biomass, Manure Biomass Biomass generation is expected to be small. Integration costs are not known. Appendix C226 1 Scenario ResultsScenario Results 2005 Integrated Resource Plan Sixth Technical Advisory Committee Meeting May 18, 2005 John Lyons 2 Scenario DefinitionScenario Definition A scenario is not modeled stochastically. Scenarios use average forecasts for hydro, load, gas, and wind generation to simulate the impact of a major change in a single assumption. The change has to be plausible and significant enough to potentially alter resource decisions. Advantages: faster solution time than stochastic modeling and easier to understand the impacts of a significant change in assumptions. Disadvantages: unable to quantitatively assess risk of market volatility. Appendix C227 3 Scenario ProcessScenario Process • Each of the scenarios were developed to help us understand the impact of a significant change in our assumptions about the future. • The values of different resources will fluctuate under different scenarios. The different resource values will be included in the final IRP. • A wind plant will be worth more than a coal plant in a high carbon tax environment. • An overall increase in the gas market will change marginal resources. • These examples show our understanding of the general direction of resource changes under different scenarios, but we still need to calculate the scenarios to understand the magnitude of the changes. • Some scenarios are calculated using Aurora because the entire WECC marketplace will be affected, while others are more easily solved outside of Aurora because they only affect Avista. 4 Gas Sensitivity ScenariosGas Sensitivity Scenarios •The high gas scenario increases average gas prices by 50% • The low gas scenario decreases average gas prices by 50% • These scenarios are designed to show to fundamental increases or decreases in the natural gas markets Average Gas Prices $0 $2 $4 $6 $8 $10 $12 $14 20 0 7 20 0 9 20 1 1 20 1 3 20 1 5 20 1 7 20 1 9 20 2 1 20 2 3 20 2 5 Low Price Base Price High Price Appendix C228 5 Gas Sensitivity Scenario ResultsGas Sensitivity Scenario Results $10 $20 $30 $40 $50 $60 $70 $80 20 0 7 20 0 8 20 0 9 20 1 0 20 1 1 20 1 2 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 Base Case High Gas Low Gas 6 Low Transmission ScenarioLow Transmission Scenario • The low transmission scenario reduces transmission capital costs by one third for every new resource type. • Accurate transmission costs are a big unknown since there has not been significant large transmission projects completed recently. This scenario gives us another view on transmission to help with our preferred strategy. Appendix C229 7 Low Transmission Scenario ResultsLow Transmission Scenario Results $35 $40 $45 $50 $55 $60 20 0 7 20 0 8 20 0 9 20 1 0 20 1 1 20 1 2 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 Base Case Low Transmission 8 High Wind Penetration ScenarioHigh Wind Penetration Scenario •The High Wind Penetration scenario assumes that 5,000 MW of wind power in the northwest is used to replace other generating resources. •This scenario is designed to find out the overall resource impact of integrating a large amount of wind into the system. Appendix C230 9 High Wind Penetration Scenario ResultsHigh Wind Penetration Scenario Results $35 $40 $45 $50 $55 $60 20 0 7 20 0 8 20 0 9 20 1 0 20 1 1 20 1 2 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 Base Case 5000 MW Wind 10 Boom Bust ScenarioBoom Bust Scenario • The Boom Bust scenario makes the assumption that a boom period of generating asset construction drives down market prices which results in a lack of new assets being developed for a period of time until markets are so tight that another building spree occurs. • This scenario was analyzed by starting with the base case and only allowing new plants to be built every five years starting in 2010. • This scenario shows the boom and bust building cycles that have been seen in recent years. Is this magnitude large enough? Appendix C231 11 Boom Bust Scenario ResultsBoom Bust Scenario Results $35 $40 $45 $50 $55 $60 20 0 7 20 0 8 20 0 9 20 1 0 20 1 1 20 1 2 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 Base Case Boom Bust 12 Emissions ScenarioEmissions Scenario • The two emissions scenarios assume that a federally mandated cap and trade program is initiated to curb greenhouse gases (GHG). • The NCEP scenario uses the analysis of the National Commission on Energy Policy. This scenario starts at $7 per metric ton of CO2 equivalent in 2010 and increases to $15 per metric ton in 2026 Gas prices do not increase under this scenario. • The EIA scenario is based upon the EIA analysis of the McCain- Lieberman Climate Stewardship Act. The act starts in 2010 with a initial price of $22 per metric ton of CO2 equivalent and increases to $60 per ton by 2026. Gas prices increase by 30% under this scenario. Appendix C232 13 Emissions Scenario ResultsEmissions Scenario Results $35 $45 $55 $65 $75 $85 $95 20 0 7 20 0 8 20 0 9 20 1 0 20 1 1 20 1 2 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 Base Case EIA Emissions NCEP Emissions 14 Fundamental Hydro Shift ScenarioFundamental Hydro Shift Scenario •The Fundamental Hydro Shift scenario assumes that the recent low water conditions are actually a permanent shift instead of temporary drought. • Average streamflow conditions are reduced by 10% in this scenario. • This scenario was developed to help us understand our resource decisions under a permanent water change. • The analysis shows that there is no significant impact on the market because gas is still on the margin. Appendix C233 15 Fundamental Hydro Shift Scenario ResultsFundamental Hydro Shift Scenario Results $35 $40 $45 $50 $55 $60 20 0 7 20 0 8 20 0 9 20 1 0 20 1 1 20 1 2 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 Base Case Hydro Shift 16 Avista Only Scenarios Avista Only Scenarios The following scenarios do not require new capacity expansion runs and have not been completed yet: • Loss of Large Avista Plant – simulates loss of Noxon for 5 years • High Avista Load – doubles the projected load growth to 4% • Low Avista Load – zero projected load growth • Loss of Spokane River Projects – All Avista projects on the Spokane River are lost • Long Haul Coal – new coal plant is sited within Avista service territory and coal is railed to the plant • Green Growth Initiative – all new Avista resources are renewable • Double Avista DSM – DSM acquisitions are doubled Appendix C234 17 Summary of Scenario ResultsSummary of Scenario Results 0 20,000 40,000 60,000 80,000 100,000 120,000 NCEP Emissions EIA Emissions High Gas Low Gas Base Case Avoided Cost High Coal Prices Hydro Shift Cheap Tx Scenario aM W o f n e w r e s o u r c e s (e x c l u d e s R P S f i x e d r e s o u r c e s ) Tar Sands Manure Geothermal Solar Nuclear IGCC SQ IGCC Pulverized WIND SCCT- Frame CCCT RPS 2026 DEFICIT Appendix C235 1 Avoided CostsAvoided Costs 2005 Integrated Resource Plan Sixth Technical Advisory Committee Meeting May 18, 2005 Clint Kalich 2 What Is An Avoided Cost?What Is An Avoided Cost? • Theoretical Price Company Would Pay For A New Resource • Based On Least-Cost Resource • Includes Both Capital and Operating Expenses of the Resource Appendix C236 3 Avoided Cost In 2005 IRPAvoided Cost In 2005 IRP • AURORA Model Run Sets Avoided Cost • Capacity Credits Assumed For Base Case Are Eliminated for AC Run – Capacity credits are used to help AURORA better emulate the regulated power supply market (i.e., over-build) – Market price with capacity credits necessarily understates cost of power since capacity credits are “theoretical” and cannot be avoided 4 Comparison of Avoided Costs and Comparison of Avoided Costs and Wholesale Market PricesWholesale Market Prices 40 42 44 46 48 50 52 54 56 58 60 20 0 7 20 0 8 20 0 9 20 1 0 20 1 1 20 1 2 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 do l l a r s p e r M W h 20-Y ear Levelized C ost B ase C ase $47.08 A voided C ost $48.32 Appendix C237 5 ConclusionsConclusions • Wholesale Marketplace Likely Understates Avoided Cost • Caused By Societal Desire To Build More Resources Than Price Alone Would Support – Reduces market volatility • 2005 IRP Shows Cost Of Extra Resources is Modest (~ $1.50/MWh, or 3%) • IRP Schedule Will Be Used In WA For PURPA <1 MW Appendix C238 1 Hydro UpgradesHydro Upgrades 2005 Integrated Resource Plan Seventh Technical Advisory Committee Meeting June 23, 2005 Clint Kalich 2 Hydro UpgradesHydro Upgrades Upgrades to Clark Fork River Project 9 Cabinet 4 9 Noxon 1 - 4 Hydro upgrades will begin September 2006 and last through March 2011 9 Each upgrade will be a 6-month project Upgrades will avoid future maintenance costs and outages and have favorable Net Present Values Appendix C239 3 Cabinet Gorge #4 Upgrade Cabinet Gorge #4 Upgrade 6 month project beginning September 2006 Increase Energy Production by 0.1 aMW and Capacity by 6 MW Expected Capital Cost of $4.7 Million Avoided Major Maintenance: N/A 20 year NPV: $4.3 Million 35 year NPV: $5.1 Million 4 Noxon Rapids #4 Upgrade Noxon Rapids #4 Upgrade 6 month project beginning September 2007 Increase Energy Production by 1.2 aMW and Capacity by 7 MW Expected Capital Cost of $3.8 Million Avoided Major Maintenance: $3.6 Million 20 year NPV: $2.5 Million 35 year NPV: $3.6 Million Appendix C240 5 Noxon Rapids #1 Upgrade Noxon Rapids #1 Upgrade 6 month project beginning September 2008 Increase Energy Production by 2.3 aMW and Capacity by 10 MW Expected Capital Cost of $4.1 Million Avoided Major Maintenance: $3.6 Million 20 year NPV: $8.3 Million 35 year NPV: $10.6 Million 6 Noxon Rapids #2 Upgrade Noxon Rapids #2 Upgrade 6 month project beginning September 2009 Increase Energy Production by 1.1 aMW and Capacity by 11 MW Expected Capital Cost of $3.8 Million Avoided Major Maintenance: $3.6 Million 20 year NPV: $2.5 Million 35 year NPV: $3.3 Million Appendix C241 7 Noxon Rapids #3 Upgrade Noxon Rapids #3 Upgrade 6 month project beginning September 2010 Increase Energy Production by 1.3 aMW and Capacity by 10 MW Expected Capital Cost of $3.9 Million Avoided Major Maintenance: $3.6 Million 20 year NPV: $5.3 Million 35 year NPV: $6.8 Million 8 SummarySummary Year Cab 4 Nox 1 Nox 3 Nox 4 Nox 2 Total Capacity (MW) 7.0 10.0 10.0 7.0 11.0 45.0 Generation (GWh) 0.6 20.4 11.8 10.2 8.8 51.8 Generation (aMW) 0.1 2.3 1.3 1.2 1.0 5.9 Capital Cost ($millions) 4.7 4.1 3.9 3.8 3.8 20.3 Avoided Major Maint. ($millions) 0.0 3.6 3.6 3.6 3.6 14.4 35-Year NPV ($millions) 5.1 10.6 6.8 3.6 3.3 29.4 20-Year NPV ($millions) 4.3 8.3 5.3 2.5 2.5 22.9 Appendix C242 1 EmissionsEmissions 2005 Integrated Resource Plan Seventh Technical Advisory Committee Meeting June 23, 2005 John Lyons 2 Current Emissions NewsCurrent Emissions News Senator Jeff Bingaman (D-NM) recently considered legislation similar to the National Commission on Energy Policy recommendations The Amended McCain-Lieberman bill was defeated on June 22nd in favor of the voluntary reductions by Senator Chuck Hegel (R-Neb.) Another attempt to reduce greenhouse gas emissions is to require a 10% renewable portfolio standard (net of hydro) by 2020 Appendix C243 3 Avista StudiesAvista Studies The Company studied and modeled the National Commission on Energy Policy and the McCain- Lieberman bill (S. 342) The company modeled these scenarios using the AURORAXMP model by adding a “tax” to CO2 production The S. 342 CO2 tax estimate was provided from the Analysis of S. 139, the Climate Stewardship Act of 2003, published in 2003 by the EIA 4 Avista Studies (cont.)Avista Studies (cont.) CO2 taxes were applied to all plants expected to produce taxable emissions Each plant has an opportunity cost of producing power or selling emission credits The studies did not include a production tax credit for renewable resources such as wind S. 342 scenario includes a small demand response reduction in load based on the study done by the EIA. The model was tasked with optimizing cost and emissions based on the estimated cap and trade costs of the two scenarios Appendix C244 5 300 350 400 450 500 550 600 650 700 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 Mi l l i o n T o n s o f C O 2 $0 $10 $20 $30 $40 $50 $60 $70 Do l l a r T a x p e r T o n o f C O 2 Base Case Emissions NCEP Emissions NCEP CO2 Tax NCEP Study Results NCEP Study Results --Emission LevelsEmission Levels Entire Western InterconnectEntire Western Interconnect 6 S. 342 Study Results S. 342 Study Results --Emission LevelsEmission Levels Entire Western InterconnectEntire Western Interconnect 0 100 200 300 400 500 600 700 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 Mi l l i o n T o n s o f C O 2 $- $10 $20 $30 $40 $50 $60 $70 Do l l a r T a x p e r T o n o f C O 2 Base Case SB 342 (Using EIA Estimated Tax) EIA CO2 Tax Appendix C245 7 200 300 400 500 600 700 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 Mil l i o n T o n s o f C O 2 Base Case Emissions NCEP Emissions S 342 Emissions Western Interconnect Emission LevelsWestern Interconnect Emission Levels 8 $30 $40 $50 $60 $70 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 $/ M W h NCEP S. 342 Base Case Comparison of Mid Columbia PricesComparison of Mid Columbia Prices 2005 Dollars2005 Dollars Appendix C246 9 21,379 20,227 18,894 18,000 19,000 20,000 21,000 22,000 An n u a l F u e l E x p e n s e ( 2 0 0 5 $ m i l l i o n s ) Base Case S. 342 NCEP Comparison of Average Annual Fuel ExpenseComparison of Average Annual Fuel Expense 2005 Dollars2005 Dollars S. 342 is a 13% increase over the Base Case NCEP is a 7% increase over the Base Case 10 ComparisonComparison--Coal GenerationCoal Generation aMWaMW 0 10,000 20,000 30,000 40,000 50,000 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 aM W Base Case S. 342NCEP Appendix C247 11 ComparisonComparison--Gas GenerationGas Generation aMWaMW 0 20,000 40,000 60,000 80,000 100,000 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 aM W Base Case NCEP S. 342 12 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 Mil l i o n s o f T o n s o f C O 2 PRS All Coal All Gas 50% Risk Avista PortfoliosAvista Portfolios--Millions of Tons of COMillions of Tons of CO22 Appendix C248 1 DemandDemand--Side ManagementSide Management 2005 Integrated Resource Plan Seventh Technical Advisory Committee Meeting June 23, 2005 Jon Powell 2 Overview • Defined 49 DSM measures – Combined two measures into one – Insufficient data to evaluate two measures • Tested against a 8760-hour avoided cost +10% • 36 measures passed the TRC test • 5.4 amW (47.5 million kWhs) pass TRC test – Local acquisition component only • Excludes 1.0 to 1.4 amW share of regional acquisition – Local acquisition 19% over current goal – Local +regional acquisition 41% to 49% over current – Overall acquisition goal exceeds share of NPCC goal • Applying IRP results in completing the tactical stage of Avista’s 2006 DSM business plan Appendix C249 3 DSM Operational Issues • Our “All Comers” tariff • Diversity of projects within an IRP category • Customer service issues • Trade Allies, Vendors, Retailers • Regional Market Transformation • Measure / Program packages 4 Integration Methodology • Integration by price – DSM is • A small acquisition on an annual basis • Currently non-dispatchable – Consequently DSM •Æ will not change the dispatch or Avista or regional resources •Æ will not influence avoided cost (not interactive with price) •Æ can be modeled as a “price taker” – An avoided cost “price signal” is sent to DSM – DSM acquires all TRC cost-effective measures relative to that avoided cost – Allows for addition and refinement of testing of DSM measures over time against the 2005 IRP avoided cost Appendix C250 5 Integration of DSM into the 2005 Electric IRP Engineering team Power Optimization Analyst team Program design team Engineering / program design team Overall DSM team Develop 8760 hour loadshapes by NPCC+ categories Estimate non-energy benefits by NPCC+ category Calculate the TRC value of each NPCC+ category Calculate the TRC acquisition cost of each NPCC+ category Calculate the TRC B/C ratio of each NPCC+ category Stack the NPCC+ categories to create a DSM TRC supply curve Review the TRC supply curve, refine program, reiterate as necessary Determine target markets and economic potential by NPCC+ categoryDetermine non- incentive utility acquisition cost by NPCC+ category Engineering Analytical calc Program design Develop 8760 x 20 year forecast of Avista avoided costs Determine customer cost by NPCC+ category 6 Assumptions • Global assumptions – Discount rate / inflation consistent with IRP forecast • TRC calculations – Two alternate approaches • TRC with NEB’s and natural gas as benefits – The traditional approach used by Avista for past reporting – Results in a more meaningful B/C ratio • TRC with NEB’s and natural gas AC as negative costs – Results in a more meaningful TRC levelized cost Appendix C251 7 Definition of the Measures • 49 measures defined – 8 industrial, 21 commercial, 19 residential, 1 utility distribution – Two PC control measures combined – CVR, rooftop HVAC measures placed on hold • Measure distinctions primarily based upon – 8760-hour load shape – Customer cost per 1st year kWh – Other characteristics (NEB, non-incentive utility cost, natural gas impact) 8 Measures eliminated Individual PC network controlsT12-T8 commercial HE A/C, skin load buildings MH to PS, manufacturing Residential W/H E to G conversion Residential prog TS, el resistance Res HE AC Res SH FS (ducted) MH to PS, parking lots Residential prog TS, heat pump MH to T5, gyms Res heat pump Non residential appliances Residential floor insulation Res SH FS (unducted) MH to PS, gyms T12-T8 schools Residential water heating efficiency Residential prog TS, AC only Residential E facing windows Residential W facing windows Residential S facing windows Non residential shell Residential N facing windows Commercial CFL School CFL Residential CFL Industrial refrigeration Industrial hydraulics Industrial pumps Industrial fans blowers HE A/C, internal load bldg Avista network computer Exit signs Industrial compressed air T12-T8 convenience retail Residential duct insulation Residential roof insulation Liquid VFDs MH to PS, commercial MH to T5, commercial Res water heating blanket Commercial HE heat pumps T12-T8 industrial Vapor VFDs Residential wall insulation MH to T5, manufacturing Measures tested Measures not tested Controlled voltage reduction Rooftop HVAC Appendix C252 9 Characterization of the Measures • 8760-hour load shape • Measure costs & benefits – Avoided electric cost – Non-energy benefits – Natural gas impact – Customer cost – Non-incentive utility cost • Calculations – TRC B/C ratio Æ NEBs and gas AC are benefits – TRC levelized cost Æ NEBs and gas AC are costs 10 The Analysis • Began with complete indexing to historical acquisition • Iterative improvement process – Fine-tuned to maximize net TRC benefits • Aggregate resource acquisition tested ranged from 4.1 amW to 7.0 amW • Final test portfolio consisted of 5.8 amW – 5.4 amW of this passing the TRC test – 36 of 46 measures tested passed • All evaluated measures stacked by TRC B/C – Creating a downward sloping supply curve • Methodology allows for post-IRP refinement to be integrated into DSM operations Appendix C253 11 DSM Supply Curve TRC B/C ratios - 50.00 100.00 150.00 - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 amW TR C B / C 12 DSM Supply Curve TRC B/C ratios (excl. TRC B/C's above 10.0) - 2.00 4.00 6.00 8.00 - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 amW TR C B / C Appendix C254 13 Traditional (upward sloping) supply curve • Graphically represent TRC levelized cost for TRC B/C ranked measures • Results in a “notched” upward sloping supply curve – Attributable to recognition of load shape in B/C ratio (not recognized in TRC levelized cost) 14 DSM Supply Curve Stacked by TRC B/C ratio $(0.500) $- $0.500 $1.000 $1.500 - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 amW Le v e l i z e d T R C c o s t Appendix C255 15 DSM Supply Curve Stacked by TRC B/C ratio (excl. windows, non-res shell) $(0.040) $(0.020) $- $0.020 $0.040 $0.060 $0.080 $0.100 - 1.00 2.00 3.00 4.00 5.00 6.00 amW Le v e l i z e d T R C c o s t 16 Regional Program Interaction • Previous measures are local utility acquired resources – Any kWh “touched” by local utility is a local kWh – Local kWh’s are excluded from regional tally –Æ Avoids double-counting of resource • (Local acquisition overestimate / regional underestimate of attribution) •Æ Generally local utility can layer share of regional acquisition on local acquisition – 2004 Avista “share” 1.4 amW • 2005 special note – Acceptance of res CFL program results in an overlap Appendix C256 17 Comparison of Aggregate DSM Goals 0 1 2 3 4 5 6 7 8 Current tariff NPCC IRP am W Local/regional Regional Agg Local 18 Distribution of Savings by Customer Segment Residential Comm / Ind Industrial Appendix C257 19 Distribution of Savings by Measure Res lighting Res HVAC Res W/H Res shell Res prog Tstat C/I lighting C/I HVAC C/I motors C/I controls C/I appliances Industrial non-process Industrial refrig Industrial fans/blowers Industrial hydraulics Industrial pumps Industrial compressed air 20 Segment distribution of acquisition • Lots of industrial – Primarily compressed air, refrig, pumps – Attributable to participant economics in new retail rate environment – Local acquisition most effective approach – Some of the most cost-effective measures • Residential – Primarily CFL’s, HE A/C, space heat fuel-efficiency – Relatively marginal TRC B/C’s – Large share of residential acquisition achieved via regional programs • Commercial – An expected level of total acquisition – Primarily lighting (as expected) Appendix C258 21 What will it cost ? • Targeted goals are achievable within a reasonable range of current DSM funding – 52% of 2002-2004 electric DSM revenues were expended • Resulting in the recovery of $10.7 million of the $11.8 million in negative electric DSM balance • Current (May ’05) combined WA / ID electric DSM balance = $0.2 million • Future DSM funding strategy – Annual revisions to DSM tariff rider sufficient to • Eliminate any positive or negative DSM forward balance • Fund all TRC cost-effective DSM acquisition in the following year 22 Total Utility Cost of DSM $- $1,000,000 $2,000,000 $3,000,000 $4,000,000 $5,000,000 $6,000,000 $7,000,000 $8,000,000 $9,000,000 2004 actual revenue 5.4 amW accepted (new tariff) 2003 4.1 amW actual (old tariff) Revenue I UC NI UC Appendix C259 23 Application of these Results • Initiation of our 2006 business planning process – Centered around appropriate stewardship of customer tariff rider funds • Target all TRC cost-effective resources appropriate for local acquisition • Currently in a transitional period – Idaho electric transition to “all CE” initiated in late 2003 – Washington gas transition initiated in early 2005 – Washington electric transition initiating in mid-2005 – Idaho gas transition will occur in late 2005 • Pending discussion with the IPUC staff and the Triple-E board 24 Progress to date • Late 2003 ramp-up of Idaho electric projects demonstrated utility incentive constraint – Effective March 2005 Idaho electric incentives were approximately doubled – Same revisions are currently in-process in Washington • Infrastructure – 2.5 FTE added via re-organization in early ’05 – 1.0 FTE of incremental field technical resources in process Appendix C260 25 Progress to date • Funding – Recovered $11.9 million of the $12.4 million negative balance left after 2001 emergency program portfolio • $11.7 million of the $11.9 million electric balance recovered – Future plan is to annually revise tariff riders to recover • forward balance • Fund acquisition efforts for subsequent year • YTD May 2005 acquisition – 5.44 amW local acquisition – Caution: extrapolating five months of data … – Not driven by Idaho incentive revisions – Retail rate response (efficiency as a substitute for energy) 26 DSM Acquisition History Electric DSM Acquisition 0.00 5.00 10.00 15.00 20.00 25.00 0 10 20 30 40 50 60 70 80 Months aM W Actual aMW aMW goal W regional NPCC 200419992000 2001 2002 2003 2005 Appendix C261 27 Mmbtu acquisition Combined Gas and Electric DSM Acquisition - 100,000 200,000 300,000 400,000 500,000 600,000 700,000 0 10 20 30 40 50 60 70 80 Month mm b t u Actual mmbtu mmbtu goal 1999 2000 2001 2002 2003 2004 2005 28 Natural Gas DSM component Gas DSM Acquisition 0 200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000 1,600,000 0 10 20 30 40 50 60 70 80 Month Th e r m s Actual therms Therm goal 2001 2002 2003 2004 2005 Appendix C262 29 Next Steps • Complete revisions in Washington electric incentives • Complete pilot projects for – Small commercial rooftop HVAC – Conservation Voltage Control • Review the role of non-utility infrastructure in the utility acquisition of DSM • Complete program design for new prescriptive residential programs identified in IRP • Review commercial / industrial DSM efforts in light of IRP results – Particular attention to industrial segment • Maintain / augment infrastructure as necessary 30 Realistic Considerations • Diversity of projects within measure category – Our “all comers” tariff issue • Alternative feedback via project-specific calculation of sub-TRC – Refine target markets – Individual assessment of efficiency opportunities • Continual re-assessment of evaluated measures • Addition of new measures as necessary Appendix C263 31 Issues for the Future • Complete rooftop HVAC pilot program and evaluation • “DSM in mass” through distribution efficiencies – Controlled Voltage Regulation • Demand-response – Capable of testing options against a “richer” 8760-hour load profile • Continued refinement of our ability to rapidly respond to changing market conditions – 2001 western energy crisis response – 2005 drought contingency plan response 32 Questions ? Appendix C264 1 Preferred Resource StrategyPreferred Resource Strategy 2005 Integrated Resource Plan Seventh Technical Advisory Committee Meeting June 23, 2005 Clint Kalich 2 Goals of PRSGoals of PRS Meet Future Capacity & Energy Requirements Keep Rates Low Stable Rates Good Performance Across Scenarios Appendix C265 3 Preferred Resource StrategyPreferred Resource Strategy——2003 IRP2003 IRP 0 125 250 375 500 625 750 875 1,000 20 0 8 20 0 9 20 1 0 20 1 1 20 1 2 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 Av e r a g e M e g a w a t t s CCCT Peakers Wind Coal 4 No Additions All Coal All Gas 50%/50% Coal/Gas All Renewables Wind/Gas No CO2 Emissions Efficient Frontier Strategies – 0% Risk – 25% Risk – 50% Risk – 75% Risk – 100% Risk Alternative Portfolio StrategiesAlternative Portfolio Strategies Appendix C266 5 Performance ComparisonPerformance Comparison——Rate Impacts Rate Impacts 20072007--1616 2.5% 3.0% 3.5% 4.0% 4.5% 5.0% 5.5% 6.0% PRS No Additions No CO2 All Renew 100% Risk 75% Risk 50% Risk 25% Risk 0% Risk All Coal All Gas Wind/Gas Coal/Gas 6 Performance ComparisonPerformance Comparison——Max Rate Max Rate IncreaseIncrease 2.5% 5.0% 7.5% 10.0% 12.5% 15.0% 17.5% 20.0% PRS No Additions No CO2 All Renew 100% Risk 75% Risk 50% Risk 25% Risk 0% Risk All Coal All Gas Wind/Gas Coal/Gas Appendix C267 7 Performance ComparisonPerformance Comparison——Capital Cost Capital Cost 20072007--26 (NPV $millions)26 (NPV $millions) - 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 PRS No Additions No CO2 All Renew 100% Risk 75% Risk 50% Risk 25% Risk 0% Risk All Coal All Gas Wind/Gas Coal/Gas 8 Performance ComparisonPerformance Comparison——2016 Incremental 2016 Incremental Power Supply Expense ($millions)Power Supply Expense ($millions) 300 325 350 375 400 PRS No Additions No CO2 All Renew 100% Risk 75% Risk 50% Risk 25% Risk 0% Risk All Coal All Gas Wind/Gas Coal/Gas Appendix C268 9 Performance ComparisonPerformance Comparison——2026 Incremental 2026 Incremental Power Supply Expense ($millions)Power Supply Expense ($millions) 400 450 500 550 600 650 700 PRS No Additions No CO2 All Renew 100% Risk 75% Risk 50% Risk 25% Risk 0% Risk All Coal All Gas Wind/Gas Coal/Gas 10 Performance ComparisonPerformance Comparison——Risk (2007Risk (2007--16 16 NPV of StDev $millions)NPV of StDev $millions) 180 185 190 195 200 205 210 215 220 225 230 PRS No Additions No CO2 All Renew 100% Risk 75% Risk 50% Risk 25% Risk 0% Risk All Coal All Gas Wind/Gas Coal/Gas Appendix C269 11 Performance ComparisonPerformance Comparison——Risk (2007Risk (2007--26 26 NPV of StDev $millions)NPV of StDev $millions) 250 275 300 325 350 375 400 425 PRS No Additions No CO2 All Renew 100% Risk 75% Risk 50% Risk 25% Risk 0% Risk All Coal All Gas Wind/Gas Coal/Gas 12 Performance ComparisonPerformance Comparison——Tail Risk (2007Tail Risk (2007-- 26 NPV of 9526 NPV of 95th th % Vs. StDev $millions)% Vs. StDev $millions) 500 525 550 575 600 625 650 675 700 725 PRS No Additions No CO2 All Renew 100% Risk 75% Risk 50% Risk 25% Risk 0% Risk All Coal All Gas Wind/Gas Coal/Gas Appendix C270 13 Performance ComparisonPerformance Comparison——NCEP Carbon NCEP Carbon Market Scenario 2016 Incremental PSEMarket Scenario 2016 Incremental PSE 300 320 340 360 380 400 420 440 PRS No Additions No CO2 All Renew 100% Risk 75% Risk 50% Risk 25% Risk 0% Risk All Coal All Gas W ind/Gas Coal/Gas m illions Base Case NCEP Em issions 14 Large Contribution from Renewable Resources 50% Higher Level of DSM Significant Reduction in Year-On-Year Rate Volatility Strong Performance Across Scenarios Reasonable Rate Impacts When Compared to Alternatives Highlights of Preferred Resource StrategyHighlights of Preferred Resource Strategy Appendix C271 15 DRAFT Preferred Resource StrategyDRAFT Preferred Resource Strategy 0 200 400 600 800 1,000 1,200 1,400 1,600 me g a w a t t s Coal CCCT SCCTWind *Other Renew DSM DSM 7 14 21 28 35 41 48 55 62 69 76 83 90 97 104 110 117 124 131 138 Other Renew 0 0 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 Wind *0 0 0 75 150 225 300 375 400 400 400 400 450 500 550 600 625 650 650 650 SCCT 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 CCCT 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Coal 0 0 0 0 0 250 250 250 250 250 250 250 350 350 350 350 350 450 550 550 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 Appendix C272